Geopark Ltd
Annual Report 2018

Plain-text annual report

ANNUAL REPORT 2018 EXPLORER OPERATOR CONSOLIDATOR CONTENTS Bottom Line Letter to Shareholders Business Approach and Guidelines 2018 Performance Our Strengths Our Platform Our Approach Our Value System Form 20-F Consolidated Financial Statements Board of Directors Management Team 1 4 16 22 24 26 29 30 33 156 210 212 Morona Block, Marañon Basin, Peru BOTTOM LINE Oil and Gas Production CAGR 21% Gas Oil Oil and Gas Reserves Gas Oil Value (2P NPV10) 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 CAGR 18% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 CAGR 26% 35 30 25 20 15 10 5 0 180 150 120 90 60 30 0 2.5 2.0 1.5 1.0 0.5 0 Morona Block, Marañon Basin, Peru Reserves and NPV figures are based on PRMS criteria GeoPark 1 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2P Reserves (mmboe)$ BillionAverage Daily Production (mboepd)2 Annual Report 2018 AS AN ENTREPRENEURIAL AND BATTLE-TESTED COMPANY THAT HAS GROWN FROM SCRATCH INTO ONE OF LATIN AMERICA’S LEADING INDEPENDENTS, WE ATTRIBUTE OUR SUCCESS TO A PROUD CULTURE BASED ON TRUST - AND WHICH IS THE CATALYST FOR OUR CONTINUOUS RECORD OF SAFE, CLEAN, NEIGHBORLY, TRANSPARENT, AND SUCCESSFUL OPERATIONS. Magallanes Region, Chile GeoPark 3 LETTER TO SHAREHOLDERS Dear Fellow Shareholders: We are pleased to report that GeoPark is a better, stronger, bigger, us the best performing upstream oil and gas company on the New smarter, and more valuable Company than last year or ever before. York Stock Exchange for the second year in a row (a 220% increase in We are vigorously marching into 2019 with a clear disciplined plan, a two years). hungry and capable team, an arsenal of innovative tools, a new high-potential country platform (our sixth country in Latin America), Reviewing improvements to key components of our business during and a strong wind at our backs to do even better next year. the year: Let’s please begin by thanking and congratulating the GeoPark team Alignment for breaking performance records across the board in 2018: As described in our Business Guidelines (accompanying every Annual Report), GeoPark’s long-term value proposition is to build the leading Record oil and gas production independent oil and gas company in Latin America – a region of • Consolidated Production Up 31% to 36,027 boepd unlimited hydrocarbon resources, with sparse competition and a • Colombia Production Up 31% to 28,545 boepd welcoming business environment. An advantage in creating our Record oil and gas reserves bold business plan that are supported and shared by our shareholders, Company has been our consistent long-term vision and a conservative • 1P Reserves Up 17% to 113.9 mmboe • 2P Reserves Up 15% to 183.7 mmboe • 3P Reserves Up 44% to 347.0 mmboe Record asset values board of directors, management and employee team. It is our steady focus on this bigger prize that has allowed us to build the foundation and tools needed for the long term and to push forward regardless of any short-term cycles or sentiment. All of our employees are shareholders and the management and Board (with friends and • Net Present Value (2P) Up 20% to $2.7 billion families) own approximately 50% of our Company, creating powerful • Net Asset Value (Debt-Adjusted) Per Share Up 37% to $40.1 alignment and incentives to perform. Record cash generation Culture • Record Revenues Up 82% to $601.2 million As an entrepreneurial and battle-tested company that has grown • Adjusted EBITDA Up 88% to $330.6 million from scratch, we attribute our achievements to a proud culture based • Free Cash Flow of $131.5 million on trust – and which is the catalyst for our continuous record of safe, Record profits • Net Income of $102.7 million • Earnings Per Share of $1.19 clean, neighborly, transparent and successful operations. We believe long-term success is defined by the underlying character and behavior of our Company, and our home-grown value system, we call SPEED, is GeoPark’s competitive advantage. It defines our success, creates positive interdependence with the communities where we operate, In the context of GeoPark’s relentless 16-year value-creation track and ensures safe and environmentally clean operational performance. record, these results demonstrate a faithful pattern of delivery that We want and expect to be the partner-of-choice, employer-of-choice has existed since our Company was founded. And, we believe our and neighbor-of-choice – and our on-the-ground metrics back this momentum is just getting stronger and stronger. up. From 2014 to date, GeoPark is the only major operator in Colombia The international investment community continued taking increased GeoPark to lead them back to the upstream utilizing a novel model notice of GeoPark’s success and rewarded our shareholders by making of development in concert with indigenous communities. In 2018, with zero work interruptions. The Peruvian government chose 4 Annual Report 2018 / Letter to Shareholders GeoPark 5 6 Annual Report 2018 / Letter to Shareholders Casanare Department, Colombia GeoPark was recognized for our social commitment with an award (1P) reserves increasing by 17% to 114 mmboe, total proven and granted by the United Nations and Colombian government. probable (2P) reserves increasing by 15% to 184 mmboe, and total proven, probable and possible (3P) reserves increasing by 44% to 347 People mmboe. The oil business begins with people and we have purposefully built the strongest oil and gas team in Latin America. Our big ambitions Cost Efficiency require us to continuously improve our overall business and prepare Being the safest, lowest-cost operator (driller and producer) of oil and for the future by increasing our capabilities and know-how in every gas are the critical factors in achieving long-term industry leadership skillset and in every country. Last year, we continued to invest in our and economic success - with an even greater emphasis due to technical, financial and management excellence and strengthen our continuously volatile oil markets. GeoPark is built to prosper in a country business unit teams by training and promoting internally and $40-50 oil price world, and our operational strength has allowed us to hiring experienced, high-quality professionals. Our focus on being relentlessly drive down capital and operating costs to achieve the best has resulted in 43% of our senior management team being top-performing metrics. Our 2P finding and development costs women. We have created a dynamic organizational and leadership were $3.6 per boe (less than $3 per boe in Colombia), and operating framework inside GeoPark that allows us to continuously adjust and costs were $8 per boe ($4 per bbl in Colombia Llanos 34). Our cost adapt to our growing enterprise and to capture the future. efficiency has resulted in 90% of GeoPark’s production being cash- flow positive at oil prices of $25-30 per boe, providing cash flow Track Record security under almost any oil price scenario. GeoPark recognizes and, in fact, welcomes the volatility that is a permanent characteristic of our industry. We have been built Value to prosper and get better in an ‘up-and-down’ world. Our risk Our preferred basic value metric is the discounted net present value management approach and our ability to identify and mitigate (NPV) of our proven and probable oil and gas reserves - since it subsurface, above-ground and macro risks to our business have encompasses the most variables impacting the recovery, cost and resulted in a unique 16-year performance track record that has financial returns of our discovered oil and gas. (It does not include prevailed despite whatever crises have been thrown at us – whether our significant exploration resource value.) With our new oil and gas from oil industry shocks, turbulent financial markets, or regional discoveries in 2018 and our increasingly efficient cost structure, the political turmoil. GeoPark is the only company in its peer group that independently-certified NPV of GeoPark’s 2P oil and gas reserves (184 can show a steady 10-year record of growth in Production, Reserves, mmboe) increased by 20% to a value of $2.7 billion. Continuing a Cash Generation, Net Present Value and Net Asset Value Per Share multi-year industry-envious capital investment efficiency record, we (with 18-26% CAGRs). Our team has proven that it has reliably invested $125 million in capex and $49 million in new acquisitions delivered over time and can be expected to continue to do so in the in 2018 and increased our NPV by more than $450 million. On a future. Hydrocarbons ‘per share’ basis and deducting outstanding net debt, our net debt adjusted 2P NPV per share increased by 37% to $40.1 per share (or nearly $26 per share for Colombia alone). This shows the underlying Enduring success in our industry means being able to consistently value of our oil and gas assets continues to grow faster than and and economically find, develop and produce oil and gas. This requires significantly ahead of our market share price. creativity, good science, discipline and the ability to take the right risks. Our team has drilled over 300 wells with a greater than 75% Upside success rate and has discovered over 350 million boe of oil and gas. GeoPark has steadily and economically built an extensive land Last year, we drilled 33 wells with an 85% success rate. We increased position across Latin America in the most prolific hydrocarbon production by 31% and exited the year with approximately 40,000 basins, with more than five million acres in 29 blocks in 10 proven boepd. After producing over 13 million boe during the year, we hydrocarbon basins in six countries – consisting of a risk-balanced replaced and grew our certified oil and gas reserves with proven mix of production, development, exploration and unconventional GeoPark 7 resource projects. With our team’s oil finding abilities, this large into Ecuador. This large dynamic platform, painstakingly constructed acreage inventory is a valuable, necessary and realistic asset for over 16 years, is one of our most powerful assets – one that does our future. On our acreage, GeoPark has identified new geological not show up on a balance sheet, but which provides the foundation plays and prospects – that is, new potential oil and gas fields – with for our long-term growth. Each country is managed by reputable externally-audited unrisked exploration resources of 600 million to and professional local teams, with supporting production and cash 1.2 billion boe. New Opportunities flows, attractive underlying reserves and resources, and inventories of new project opportunities. Our independent country businesses benefit from the support of our overall corporate organization, With our focus on scale, GeoPark is always in the hunt to acquire which improves efficiencies, reduces costs through operational and new oil and gas upstream opportunities across Latin America and financial synergies, controls quality, drives performance, and more we have been patient and selective in identifying and acquiring new effectively grows our overall company by allocating capital to the high-quality projects on attractive terms. We begin with a technical best shareholder value-adding projects. approach to identify under-exploited proven hydrocarbon basins – considering geological, infrastructure and regulatory factors – and Country Businesses then work to establish strategic positions in the targeted regions. Our continuous efforts over the last 10+ years have resulted in a A brief look at each of our businesses: $4+ billion new project inventory in Colombia, Brazil, Argentina, Peru, Ecuador and Mexico. We have initiatives with the key Latin Colombia Business American national oil companies, which control the biggest and GeoPark is leading the strongest upstream project in Colombia, one best hydrocarbon acreage in each country and are reevaluating their of the most attractive onshore projects in Latin America today. In portfolios to initiate divestment programs. To enhance our position as less than five years we grew from zero to become the second-largest the preferred buyer in the region, GeoPark entered into an acquisition private oil operator in the country – and are currently proving up partnership in 2018 with ONGC, the national oil company of India, what is being called the largest oil field discovery in Colombia in the to strengthen our expansion efforts. (India is the fastest-growing oil last 20 years. consumer in the world.) Self-Funding Our key asset is the Llanos 34 Block (GeoPark discovered and operated), which we have grown from 0 to 70,000+ bopd gross Differentiating us from most of our industry peers, GeoPark is a production – following our introduction of a new geological play type self-funding growing cash-generating company – by which we mean to the Llanos Basin. During 2018, after successful appraisal drilling we are getting bigger and better by paying out of our own pocket. in the Tigana and Jacana oil fields and new oil field discoveries in This represents an important advantage, which is further bolstered by Chachalaca Sur and Tigui, we materially increased our Colombian our capital investment efficiency. Cash flows from operating activities certified PDP, 1P, 2P and 3P reserves by 61%, 20%, 26% and 43% to increased 80% to $256.2 million and Adjusted EBITDA increased by 34.7 million boe, 79.5 million boe, 111.2 million boe and 145.6 million 88% to $330.6 million. We had $131.5 million of free cash flow with a boe respectively. Our 2P reserve life index reached 10.7 years and 15% yield – and profits of $102.7 million. We have a history of raising the reserve replacement ratio was 321%. Our 1P NPV and 2P NPV in capital creatively – and our balance sheet is strong with $128 million Colombia increased to $1.4 billion and $1.9 billion respectively. in cash and a net debt to Adjusted EBITDA ratio of 1.0X - showing our ability to effectively manage and use leverage to expand our Llanos 34 is a highly attractive, low risk, low cost and high netback business. Platform block which provides a large-scale profitable production base even in low oil price environments. Due to the expertise of our local teams, net finding and development costs (F&D costs) for 2018 were just $2.9 GeoPark’s business plan and systematic expansion to date has per boe (2P). We have a big inventory of well sites (80+) to continue resulted in building stable and growing independent businesses in growing production, and well economics with three digit IRRs and Colombia, Chile, Brazil, Argentina and Peru – with a recent new entry six-month paybacks (assuming a $50-55 per barrel Brent oil price). 8 Annual Report 2018 / Letter to Shareholders Aguada Baguales Block, Neuquen, Argentina GeoPark 9 Our return on capital in Llanos 34 is highly profitable and beats almost any North American conventional or unconventional play. In a constant effort to reduce costs and improve netbacks, we constructed a new 30 km flowline to connect Llanos 34 to the main Colombian pipeline infrastructure which will become operational in early 2019. During 2018, GeoPark also added new acreage adjacent to Llanos 34 and acquired LG’s 20% equity interest in our Colombian subsidiary, which owns our participation in Llanos 34. Peru Business GeoPark continues working to prepare for the development of the Morona Block. This project has become emblematic for Peru and, because of our operating, environmental and community track record, GeoPark was selected as the company to lead Petroperu back to the upstream business and to operate this important and complex project with a 75% working interest. We are actively engaged with members of the communities and federations in the area of direct influence to cooperate on the Environmental Impact Assessment, which was submitted in 2018. The Smithsonian Institution of Washington DC entered into a partnership with GeoPark to study and monitor the biodiversity of the focus area. Morona is a large block in the proven Marañon Basin with a large upside potential (approximately 300-500 million boe) with several high-impact plays and prospects. The block’s key asset is the Situche Central light oil field, which was discovered and proven up by two wells (which tested at a combined rate of 7,500 bopd), and which has certified gross 3P reserves of 198.3 million barrels (with a gross NPV of $2+ billion) and the opportunity for near-term cash flow. 10 Annual Report 2018 / Letter to Shareholders Morona represents an important project for GeoPark that significantly increases our overall inventory of reserves and exploration resources and can contribute to our long-term durable growth. GeoPark has designed a phased work program that is expected to put the Situche Central field into production initially through a long-term test to begin generating cash flow – with ‘first oil’ targeted for 2020. Argentina Business Our team is continuing to strengthen our position in Argentina, where it has a proven history of exploration success. In March 2018, we acquired a 100% working interest in and operatorship of three new blocks (Aguada Baguales, El Porvenir and Puerto Touquet) in the heart of the Neuquen Basin with production, development, exploration and unconventional resource potential. The blocks are currently producing 2,300-2,400 boepd and were acquired at a value of $4 per boe 2P reserves. Exploration of a new tight gas play began in early 2019. In addition to its attractive upside potential, this acquisition represents a good fit with our existing platform in Argentina with the opportunity for future cost savings and operational synergies. GeoPark also entered into a partnership with YPF, the national oil company of Argentina, on the Los Parlamentos block – a large high-potential exploration block in the Neuquen Basin with both conventional and unconventional prospects. Brazil Business Our Brazil business represents a strategic base with a fully developed, secure, cash flow-producing asset (a non-operated interest in the Manati field, one of Brazil’s largest producing gas fields, operated by Petrobras) and 7 exploration blocks in onshore mature proven hydrocarbon basins (Potiguar, Reconcavo, and Sergipe Alagoas). GeoPark is currently preparing to test a new exploration well drilled in the Reconcavo Basin. GeoPark also has identified attractive onshore and shallow offshore hydrocarbon opportunities in Brazil, and is working with Petrobras in its ongoing divestment efforts. Tua Field, Llanos 34 Block, Colombia GeoPark 11 Chile Business Ecuador Business GeoPark is Chile’s first private oil and gas producer. We built the In March 2019, GeoPark was awarded two low-risk high-potential business from a flat-footed start-up in 2006 to a solid business with exploration blocks in north-eastern Ecuador in the Oriente Basin. current production of approximately 2,800 boepd (80% gas, 20% Both blocks are covered with 3D seismic and are adjacent to multiple oil), 2P reserves of 24.7 million boe and 5 blocks with 0.8 million producing oil fields and existing infrastructure. Ecuador has Latin acres, consisting of approximately 300-800 million boe of gross America’s third-largest oil reserves and the Oriente Basin is producing exploration and unconventional resources. Over 20 million boe have over 500,000 bopd, with infrastructure with spare capacity and a already been produced by GeoPark in Chile and we divested 20% of well-developed service industry. The award of these blocks is subject our project in 2011 for approximately $150 million. This interest was to regulatory approval and contract execution – and operational recently re-acquired by GeoPark in November 2018. start-up is targeted for late 2019 or early 2020. In 2018, we discovered the Jauke gas field in the Fell Block, which is part of the large Dicky geological structure, which has the potential for multiple development drilling opportunities, some of them to be tested in 2019. 12 Annual Report 2018 / Letter to Shareholders Outlook GeoPark has developed and proven-up a highly effective and robust The 2019 work program provides for: capital allocation methodology to manage its six-country portfolio. This system enables us to review and select from a wide range of • 35+ gross well drilling program targeting production growth of 15% projects generated by each business unit team with different returns, • 27-30 gross well development, appraisal and exploration drilling potentials, risks, sizes, timelines and geographies. It ensures that program in the Llanos Basin in Colombia capital is always directed to our top value-adding projects after • 6-7 gross well exploration and development drilling program in the ranking them on technical, strategic and economic criteria. It creates Neuquen Basin in Argentina in operated and non-operated blocks a healthy competition between our different business units which • Early production facilities in the Morona Block in the Marañon Basin further helps drive performance. It also provides greater security in Peru with the goal of putting the Situche Central light oil field into in volatile markets by allowing us to easily add or remove projects production by 2020, subject to approval of the Environmental Impact depending on oil prices and project performance – and to fine-tune Assessment our desired risk exposure. • 2-3 gross well exploration and development drilling program on the Our 2019 work and investment program targets a $220-240 million • 1-2 gross well shallow exploration drilling program in the onshore capital investment program (considering Brent oil prices of $65-75 Reconcavo and Potiguar Basins in Brazil Fell Block in the Magallanes Basin in Chile per barrel) and is fully funded by cash flows. As always, our flexible work program includes an accelerated case for higher oil prices and a reduced program for lower oil prices. Casanare Department, Colombia GeoPark 13 14 Annual Report 2018 / Letter to Shareholders Thank You Thank You As our history has proved, great people create great results. We are Our sincere thanks and appreciation to our shareholders and pleased to recognize and thank the women and men who have bondholders – old and new alike – who have partnered with us, built and are continuing to build GeoPark. They are our heart and believe in our project, and support our efforts. In 2018, we continued our muscle, and have met every challenge with a professionalism, our campaign (over 450 meetings) to reach out to new investors creativity and agility that continues to propel us forward. and better align our market value with the underlying asset value we have unlocked in the field. As a result, we were the leading E&P Our gratitude extends to the persistently supportive families of all stock performer for the second year in a row and our stock trading our team members who have contributed immensely to what we volumes have begun to accelerate (now at levels exceeding $5 million have achieved and where we are going. We were fortunate to join per day) which has opened up shareholder participation to the wider with all employees and spouses in 2018 in Villa de Leyva, Colombia investment community. for GeoPark’s Fifteenth Anniversary to express our thanks personally and to celebrate together our culture, accomplishments and big As always, your comments and recommendations are welcomed and expectations for each other. appreciated. We please invite you to visit us in the field or at any of our offices to get to know us better and learn first-hand how we work. A special thanks also to our committed and experienced Board of Directors who work continuously to improve GeoPark. We are very We look forward to delivering and reporting to you on our results in pleased to welcome Constantine Papadimitriou who joined our Board 2019. in 2018 and will also serve on the Audit Committee. Sincerely, Gerald E. O’Shaughnessy Chairman James F. Park Chief Executive Officer GeoPark 15 BUSINESS APPROACH AND GUIDELINES Strategic Context GeoPark’s objective is to create value by building the leading Latin opportunities. By applying new technology and investment, American upstream independent oil and gas company. By this, we creating stable markets and better economic conditions, and/or mean an action-oriented, persistent, aware and caring company more efficient operations, an under-performing or bypassed asset with the best ‘shareholder value-adding’ oil and gas assets. can be converted into an attractive economic project. Work in these proven areas also frequently opens up exciting new hydrocarbon We believe the energy business – specifically the upstream oil resources in new geological play types and formations. and gas industry – is one of the most exciting, necessary, and economically-rewarding businesses today. No undertaking or We are focused on Latin America because of the abundance of society can advance without the supply of energy, and energy these types of opportunities throughout the region. Latin America remains the critical element in allowing people to better their lives. ranks as one of the highest potential hydrocarbon resource Much of the world still lacks adequate energy supplies for the most regions in the world and its economies are thirsty for new energy. basic needs and demand is continually increasing. Although new Historically, it has been dominated by larger major and national exciting technologies and sources are being developed, oil and gas oil companies, with the presence of only a modest number of is the most reliable energy source and will be required to support more-agile independent companies. North America is home to over half of our planet’s continuous and rising energy needs far into thousands of independent oil and gas operators, whereas Latin this century. America, an area substantially larger and with greater resource potential, has only a handful of independents taking advantage of We believe the best places for us to find and develop hydrocarbons available opportunities. In contrast to many areas of the world, the are in areas around the world where oil and gas have already environment and resources for operating and funding a business been discovered, but which for economic, technical, funding or are welcoming and increasingly more feasible. Furthermore, other reasons have been inadequately developed or prematurely numerous good oil and gas assets in Latin America are available, abandoned. These projects have proven hydrocarbon systems, undervalued and at very attractive prices now. valuable technical information, existing infrastructure, and, in many cases, unexploited low-risk exploration and re-development GeoPark has been conservatively built for the long term. We did not 16 Annual Report 2018 / Business Approach and Guidelines El Porvenir Block, Neuquen, Argentina start with a short term ‘exit strategy’ in mind and we have focused year-over-year track record is evidence of our success in effectively on building a team and sustainable business. Our approach has balancing risk among the subsurface, geological, funding, required patience in order to create the necessary foundation, but organizational, market, price, partner, shareholder, regulatory and it has enabled us to stay solidly ‘in the game’ and be positioned to political environments. For example, GeoPark was able to respond now have the chance to grab the bigger prizes. constructively to the 2008/9 financial crisis and, again, to the oil price volatility of 2015-2016. The founders and our management team have a substantial part of our net worth invested in GeoPark. (The CEO founder has never sold We believe the best results in the upstream business are achieved a share of GeoPark stock.) The management team has no special with a larger scale portfolio approach with multiple attractive class of stock or arrangements that benefit us differently from any projects in multiple regions managed by talented oil and gas other shareholder other than our salaries and stock performance teams. This diversification reflects both a defensive and offensive incentive programs. The entire GeoPark team (100% of our approach. It is protective of any downside because the collective employees have received GeoPark share awards) is solidly aligned strength of our projects limits the negative impact of any with all of our shareholders to build real and enduring value for underperforming asset or timing delay. It also has an exciting every share of GeoPark. Opportunity Enhancement and Risk Diversification By its very nature, the upstream oil and gas business represents multiplier effect on the potential upside because of the increased number of opportunities independently marching ahead. These represent important advantages given the nature of the oil exploration and production business. Our country businesses are managed by experienced local the undertaking of risk in search of significant rewards. To succeed, professionals and teams with respected reputations. They know an oil and gas company must effectively identify and manage both the specific subsurface rocks and conditions and the above- prevailing risks and uncertainties to capture the available rewards. ground operating and business environments in each region and We believe this to be one of GeoPark’s key capabilities; and our give us the characteristics of a local company. Our pride and care in GeoPark 17 how we act and perform in our home regions are key elements of skill sets – as Explorers, Operators and Consolidators – which we our success. deem critical for enduring success in the oil and gas business. Our team has consistently demonstrated the science and creativity to find These generally independent businesses are further enhanced hydrocarbons in the subsurface, but also the muscle and experience by being tied together by an overall corporate organization, to get the oil and gas out of the ground and profitably to market. which improves efficiencies, reduces costs with operational and Our attractive asset portfolio is evidence of our ability to acquire financial synergies, controls quality, and can more effectively raise good projects in the right basins in the right countries with the right capital for our projects. It also is a source for new technologies partners and at the right price. and ideas to spread from one region to another. For example, our team introduced a new geological play-type to the Llanos Basin in Today, we have an amazing team of employees from Chile, Colombia, Colombia (an area that has been explored for more than 75 years) Brazil, Peru and Argentina – each of whom joined GeoPark with the that resulted in multiple new oil field discoveries, and new oil purpose of building a unique and special company that is prepared technology to the Magallanes Basin in Chile. to handle challenges and seize opportunities. As a quickly growing company, we have repeatedly seen individuals step up to the new Importantly, through effective and controlled capital allocation, our responsibilities presented – and we have a deep and powerful projects within each country business can be ranked against each leadership team taking GeoPark to the next level. other on economic, technical and strategic criteria and, therefore, ensure our capital resources flow to the highest performing and The international upstream oil and gas business is not for the most attractive projects. fainthearted or easily discouraged. Time-after-time, the GeoPark team has been able to push ahead to find solutions where often We believe this business approach makes GeoPark a more others have given up or failed. This is the engine and fire of our attractive investment vehicle for all our shareholders – with a growth and the true long-term intangible value of our Company. strong foundation to minimize any downside, a big upside through We are immensely grateful to all these men and women for their multiple growth opportunities, and an overall organizational professionalism, discipline, unity and heart. system to more efficiently run and grow the individual businesses. GeoPark’s model allows our investors to be exposed to and benefit from the results of multiple supporting and aligned businesses across diverse geologies and geographies. Capabilities Our experience in the oil and gas business has repeatedly New Projects and Countries We are excited about potential new business opportunities in Latin America with its high resource potential, attractive business environment, and limited competition. We are actively pursuing new projects in targeted proven hydrocarbon basins throughout the region – selected in consideration of geological, infrastructure demonstrated the need for good people with commitment and and regulatory factors – with our principal efforts in Colombia, Brazil, real oil and gas know-how. We believe in and have experienced the Chile, Peru, Argentina, Ecuador and Mexico. amazing capacity of people to excel in an environment of expanding opportunity and trust. GeoPark is blessed to have an incredible group With our overall growth targets and portfolio approach, new project of men and women who truly work day and night to make us better acquisitions are an important part of our business. Our acquisition in every way. Our results speak to the daily heroics (mostly unseen) efforts begin with a technical approach to define the hydrocarbon by our team that keep us together and have moved us consistently basins where our geological and engineering teams identify an closer to our goals. attractive potential. After screening for political risks, our new business teams proactively ‘scratch and dig’ to locate interests or Our record of delivery is based on three fundamental and distinct opportunities within those areas and to establish a position. It is 18 Annual Report 2018 / Business Approach and Guidelines GeoPark 19 20 Annual Report 2018 / Business Approach and Guidelines El Porvenir Block, Neuquen, Argentina a long-term and continuous effort and we have been building an Culture ‘Creating Value and Giving Back’ is our motto and represents attractive inventory of new projects in the region over the last ten GeoPark’s market-based approach to align our business objectives years, aided by our team’s 25+ year experience in Latin America. with our core values and responsibilities. Our in-house designed program, titled SPEED, targets and integrates the critical elements Our focus is always to build a larger-scale balanced portfolio that – Safety, Prosperity, Employees, Environment and Community includes lower-risk short term cash flow generating properties, Development – necessary to make our total business plan work. Only mid-term medium-risk development projects, and longer term by succeeding equally in each of these interdependent areas can we higher-risk big upside projects. This permits steady, secure growth realize our overall success and ambitions. This is important in every with an opportunity for accelerated high growth ‘home-runs’ from country where we operate, and we make every effort to achieve the bigger projects. the most effective governance, full compliance and consistent transparency with all relevant authorities. Not only does this allow Good oil and gas partners are a key element of our new business us to be a more successful business enterprise over the long term, it efforts and we like to balance our acquisition risk by including reflects our pride in carrying out an important mission in the right experienced partners in our new projects. We operated a strategic way. The men and women of GeoPark care passionately about how alliance with LG of Korea to acquire upstream assets and the our Company acts – both internally and externally – and we all International Finance Corporation (IFC) of the World Bank has been consider our culture to be our core asset and the prime source of our a long-term principal shareholder of (and sometimes lender to and past success and future opportunity. working interest partner of ) GeoPark. [In 2018, we established a long-term strategic partnership with ONGC, the national oil company The world is continuously moving in a more regulated direction of India, to build a large-scale portfolio of upstream assets across with higher expectations, and to be able to operate in this new Latin America.] We also have developed long-term relationships with environment is a fundamental part of business today. We believe that the national oil companies where we operate, such as with ENAP in GeoPark’s ability to meet these challenges and perform to or beyond Chile, Ecopetrol in Colombia, Petrobras in Brazil, YPF in Argentina, these ever-increasing standards represents a competitive advantage Petroperu in Peru, and Petroamazonas in Ecuador. for the future. For example, the results from and impact on the communities of our overall work and efforts in Chile and Colombia Critical to the success of any new project is to conduct a thorough provided the rationale and support for the government and regional technical and economic analysis prior to acquiring any new asset. community to encourage us to expand our project into new areas. We make sure we understand the project, its risks and its value – The World Bank’s IFC, a founding shareholder, has been a constructive and we buy right. It is difficult to turn a faulty or overpriced project force in helping us operate and manage our business in consideration into a good business. Following intensive geological, geophysical, of the environment and communities around us. The IFC further engineering, operational, legal and financial analyses and due assisted us by carrying out annual audits and physical site visits of diligence, we perform a detailed discounted cash flow (DCF) both our regulatory compliance and best-practices approach. valuation. We also consider the option value or strategic benefits of a project when entering a new region. We do not buy assets on simplified ‘$ per barrel’ metrics which we believe do not properly account for multiple factors (including technical, cost, tax, and time) that impact the economics of oil and gas projects. We also avoid markets or ‘bubbles’ when assets are over-priced. - James F. Park, 2008+ GeoPark 21 2018 PERFORMANCE Record Oil and Gas Production • Production up 31% to 36,027 boepd Record Cost and Investment Efficiencies • Capital investment program of $174 million Portfolio Expansion and Acreage Growth • Acquired LG’s 20% equity interest in • Colombia production up 31% to 28,545 generated $454 million in 2P NPV10 GeoPark’s Chilean and Colombian bopd • Adjusted EBITDA/capital expenditure ratio of subsidiaries, including Llanos 34 Block • Record exit production of 39,600 boepd 1.9x • Agreed to South American acquisition Record Oil and Gas Reserves • 1P reserves up 17% to 113.9 million boe • 2P reserves up 15% to 183.7 million boe • Colombia 2P reserves up 26% to 111.2 million bbl Record Asset Values • 1P reserve NPV10 up 17% to $1.8 billion • 2P Finding and Development costs: partnership with ONGC, the national oil Consolidated $3.6/boe; Colombia $2.9/boe company of India • OPEX: Consolidated $8 per boe, Llanos 34 • Divested high-cost, non-core La Cuerva and Block $4 per boe Yamu Colombian assets Record Cash Generation • Revenues up 82% to $601.2 million • Acquired new low-cost large exploration acreage in the Neuquen Basin in Argentina in partnership with YPF • Adjusted EBITDA up 88% to $330.6 million • Closing of low-cost, cash flow producing • Cash flow from operations up 80% to 256.2 acquisition with development, exploration million and unconventional resource upside in the • 2P reserve NPV10 up 20% to $2.7 billion • Net debt to Adjusted EBITDA ratio decreased Neuquen basin in Argentina • 2P reserve Colombian assets NPV10 up 35% to 1.0x from 1.7x to $1.9 billion • Net debt adjusted 2P NPV10 increased by 37% to $40.1 per share Record Profits • Net income of $102.7 million • Earnings per share of $1.19 Market Performance • Top performing E&P company on NYSE for second year in a row (220% increase in two years) • Free cash flow of $131.5 million • Continued improving market visibility with • $127.7 million of cash in hand an average daily stock trading volume of $4.3 million 2007 2008 2009 2010 2011 2012 22 Annual Report 2018 / Performance  Oil Gas 2019 Outlook • Capital investment program of $220-240 million • Drilling program of 35+ exploration, appraisal and development wells in Colombia, Argentina, Brazil and Chile • Targeting organic production growth of ~15% • 2019 work program is fully funded with cash flows and can be adapted to provide production growth under different oil price scenarios ) d / e o b M ( n o i t c u d o r P s a G d n a l i O y l i a D e g a r e v A 35 30 25 20 15 10 5 0 2013 2014 2015 2016 2017 2018 GeoPark 23 OUR STRENGTHS People Proven Capabilities Across Full E&P Value Chain Track-Record 16-Year Continuous Operational and Financial Growth Upside Organic Exploration and New Acquisition Growth Projects Value Proven Oil and Gas Assets With 2P NAV of $2.4 Billion ($40.1/Share) Self-Funding Cash Flow Pays for Building the Business Platform Unique Long-Established High-Impact Risk-Balanced Asset and Operating Base Across Latin America 24 Annual Report 2018 / Our Strengths Morona Block, Marañon Basin, Peru Morona Block, Marañon Basin, Peru GeoPark 25 OUR PLATFORM Mexico 26 Annual Report 2018 / Our Platform Mexico Ecuador 2 Blocks1 0.03 mm Acres Peru 1 Block 1.9 mm Acres 30.3 mmboe Argentina 7 Blocks2 2.2 mm Acres 14.2 mmboe Chile 5 Blocks 0.8 mm Acres 24.7 mmboe Colombia 6 Blocks 0.3 mm Acres 111.1 mmboe Brazil 8 Blocks3 0.3 mm Acres 3.2 mmboe Latin American Platform 2P Reserves (Dec. 2018) Production Assets Development Assets Exploration Assets Unconventional Resource Assets New Project Opportunities 1Subject to final signature of the contracts 2Includes Los Parlamentos Block subject to regulatory approvals 3Includes PN-T-597 Block subject to entry into the concession agreement by ANP GeoPark 27 28 Annual Report 2018 / Our Approach Meta Department, Colombia OUR APPROACH GeoPark has been built around five fundamental and distinct capabilities: Explorer The ability, experience, methodology and creativity to find and develop oil and gas reserves in the subsurface – based on the best science, solid economics and ability to take the necessary managed risks. Operator The ability to execute in a timely manner and the know-how to profitably drill for, produce, treat, transport and sell our oil and gas – with the drive and persistence to find solutions, overcome obstacles, seize opportunities and achieve results. Consolidator The ability and initiative to assemble the right balance and portfolio of upstream assets in the right hydrocarbon basins in the right regions with the right partners and at the right price – coupled with the vision and skills to transform and improve value above ground. Value Risk Management The comprehensive management approach to consistently and significantly grow and build economic value per share by effective planning, balanced work programs, cost efficiency focus, secure access to capital sources, reliable communication with shareholders, and by accommodating risk among the subsurface, funding, organizational, market, partner/shareholder, and regulatory/political environments. Culture The commitment to build a unique performance-driven trust-based culture which values and protects our shareholders, employees, environment and communities to underpin and enhance our long-term plan for success. Our SPEED program reflects this value system and represents an integrated approach to align our business objectives with our core principles and responsibilities. Meta Department, Colombia GeoPark 29 OUR VALUE SYSTEM SPEED represents GeoPark’s underlying value system which provides us the leadership, confidence and foundation required for long-term success. It is our competitive advantage. And, it reflects our pride in achieving an important mission in the right way. If we are the true performer, the best place to work, the preferred partner and the cleanest operator – our future is bigger, better and more secure. Safety Prosperity Employees Environment ZERO Vehicle  accidents in 6 mm km 220% Stock price increase since December 2016 100% Employees are Shareholders ISO 14001 Certified in Colombia. 100% Licenses Approved OD O G NEIG H B O R AN H GeoPark is committed GeoPark is committed GeoPark is committed GeoPark is committed GeoPark is committed to creating a safe and to delivering to creating a motivating to minimizing the to being the preferred healthy workplace. significant bottom-line workplace for impact of our projects neighbor and partner Simply speaking, financial value to our employees. With today’s on the environment. by creating a mutually everybody must return shareholders. Only shortage of capable As our footprint beneficial exchange home everyday safe a financially-healthy energy professionals, the becomes cleaner and with the local and sound. company can continue company which is able smaller, the more areas communities where we to grow, attract needed to attract, protect, retain and opportunities will work. Unlocking local resources and create real and train the best team be opened up for us to knowledge creates and long-term benefits. with the best attitude work in. Our long-term supports long-term will always prevail. well-being requires sustainable value in our us to properly fit within projects. If our efforts our surroundings. enhance local goals and customs, we will be invited to do more. 30 Annual Report 2018 / Our Value System 12015-2019 GeoPark 31 HIGHLIGHTED SECTIONS 44 64 108 127 135 156 Risk Factors Information on the Company Operating and Financial Information Directors and Management Major Shareholders and Related Parties Consolidated Financial Statements 32 Annual Report 2018 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) Form 20-F REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 OR ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2018 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________________ to ________________ OR SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report Commission file number: 001-36298 GeoPark Limited (Exact name of Registrant as specified in its charter) Bermuda (Jurisdiction of incorporation) Nuestra Señora de los Ángeles 179 - Las Condes, Santiago, Chile (Address of principal executive offices) Pedro E. Aylwin Chiorrini Director of Legal and Governance GeoPark Limited Nuestra Señora de los Ángeles 179 - Las Condes, Santiago, Chile Phone: +56 (2) 2242 9600 - Fax: +56 (2) 2242 9600 ext. 201 (Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person) Copies to: Maurice Blanco, Esq. Yasin Keshvargar, Esq. Davis Polk & Wardwell LLP 450 Lexington Avenue - New York, NY 10017 | Phone: (212) 450 4000 - Fax: (212) 701 5800 Securities registered or to be registered pursuant to Section 12(b) of the Act: Title of each class Common shares, par value US$0.001 per share Name of each exchange on which registered New York Stock Exchange Securities registered or to be registered pursuant to Section 12(g) of the Act: None (Title of Class) Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None (Title of Class) Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of business covered by the annual report. Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No Common shares: 60,483,447 If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer Accelerated filer Non-accelerated filer Emerging growth company If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. † The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012. Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: US GAAP International Financial Reporting Standards as issued by Other the International Accounting Standards Board If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow. Item 17 Item 18 If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No GeoPark 33 Table of Contents PRESENTATION OF FINANCIAL AND OTHER INFORMATION FORWARD-LOOKING STATEMENTS PART I 37 40 41 ITEM 10. ADDITIONAL INFORMATION A. Share capital B. Memorandum of association and bye-laws ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS 41 Enforcement of Judgments 139 139 139 144 145 145 145 148 148 148 148 148 C. Material contracts D. Exchange controls E. Taxation F. Dividends and paying agents G. Statement by experts H. Documents on display I. Subsidiary information ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 148 A. Debt securities B. Warrants and rights C. Other securities D. American Depositary Shares PART II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES A. Defaults B. Arrears and delinquencies ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS ITEM 15. CONTROLS AND PROCEDURES A. Disclosure Controls and Procedures B. Management’s Annual Report on Internal Control over Financial Reporting C. Attestation Report of the Registered Public Accounting Firm D. Changes in Internal Control over Financial Reporting ITEM 16. RESERVED ITEM 16A. Audit committee financial expert ITEM 16B. Code of Conduct ITEM 16C. Principal Accountant Fees and Services ITEM 16D. Exemptions from the listing standards for audit committees ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers ITEM 16F. Change in registrant’s certifying accountant ITEM 16G. Corporate governance ITEM 16H. Mine safety disclosure PART III ITEM 17. Financial statements ITEM 18. Financial statements ITEM 19. Exhibits Glossary of oil and natural gas terms Index to Consolidated Financial Statements 148 148 148 148 148 148 148 148 149 149 149 149 149 149 149 149 149 149 150 150 150 150 151 145 152 152 152 154 159 A. Directors and senior management B. Advisers C. Auditors ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE A. Offer statistics B. Method and expected timetable ITEM 3. KEY INFORMATION A. Selected financial data B. Capitalization and indebtedness C. Reasons for the offer and use of proceeds D. Risk factors ITEM 4. INFORMATION ON THE COMPANY A. History and development of the company B. Business Overview C. Organizational structure D. Property, plant and equipment ITEM 4A. UNRESOLVED STAFF COMMENTS ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS A. Operating results B. Liquidity and capital resources C. Research and development, patents and licenses, etc. D. Trend information E. Off-balance sheet arrangements F. Tabular disclosure of contractual obligations G. Safe harbor ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES A. Directors and senior management B. Compensation C. Board practices D. Employees E. Share ownership ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS A. Major shareholders B. Related party transactions C. Interests of Experts and Counsel ITEM 8. FINANCIAL INFORMATION A. Consolidated statements and other financial information B. Significant changes ITEM 9. THE OFFER AND LISTING A. Offering and listing details B. Plan of distribution C. Markets D. Selling shareholders E. Dilution F. Expenses of the issue 34 GeoPark 20F 41 41 41 41 41 41 41 41 45 45 45 66 66 68 110 110 110 110 110 126 128 128 128 128 129 129 129 134 136 137 137 138 138 138 138 138 138 138 139 139 139 139 139 139 139 Presentation of Financial and Other Information Certain definitions Unless otherwise indicated or the context otherwise requires, all references in this annual report to: • “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words of a similar effect, are to GeoPark Limited (formerly GeoPark Holdings Limited), an exempted company incorporated under the laws of Bermuda, together with its consolidated subsidiaries; • “Agencia” are to GeoPark Latin America Limited Agencia en Chile, an established branch, under the laws of Chile, of GeoPark Latin America Limited (“GeoPark Latin America”), an exempted company incorporated under the laws of Bermuda; • “GeoPark Colombia” are prior to our internal corporate reorganization of our Colombian operations, to our subsidiary GeoPark Colombia S.A., a sociedad anónima cerrada incorporated under the laws of Chile and subsequent to such reorganization, to GeoPark Colombia Coöperatie U.A., a cooperative duly incorporated under the laws of the Netherlands; • “LGI” are to LG International Corp., a company incorporated under the laws of Korea”; • “Notes due 2024” are to our 2017 issuance of US$425.0 million aggregate principal amount of 6.50% senior notes due 2024; • “US$” and “U.S. dollar” are to the official currency of the United States of America; • “Col$” is the official currency of Colombia; • “Ch$” and “Chilean pesos” are to the official currency of Chile; • “AR$” and “Argentine pesos” are to the official currency of Argentina; • “real,” “reais” and “R$” are to the official currency of Brazil; • “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis); • “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos); • “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de Petróleo) • “UTA” are to Unidad Tributaria Anual; • “economic interest” means an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires; and • “working interest” means the right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis. GeoPark 35 Financial statements Non IFRS financial measures Our consolidated financial statements Adjusted EBITDA This annual report includes our audited consolidated financial statements as management and external users of our financial statements, such as industry of December 31, 2018 and 2017 and for each of the years ended December 31, analysts, investors, lenders and rating agencies, to assess the performance of 2018, 2017 and 2016 (hereinafter “Consolidated Financial Statements”). our Company and the operating segments. Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by Our Consolidated Financial Statements are presented in US$ and have been We define Adjusted EBITDA as profit for the period before net finance cost, prepared in accordance with International Financial Reporting Standards income tax, depreciation, amortization and certain non-cash items such (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). as impairment charges or impairment reversals, write-offs of unsuccessful Our Consolidated Financial Statements have been audited by unrealized gains in commodity risk management contracts and bargain Price Waterhouse & Co. S.R.L., Argentina (“PwC”), a member firm of purchase gain on acquisition of subsidiaries. Adjusted EBITDA is not a measure PricewaterhouseCoopers Network, an independent registered public of profit or cash flows as determined by IFRS. exploration and evaluation assets, accrual of stock options and stock awards, accounting firm, as stated in their report included elsewhere in this annual report. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our Our fiscal year ends December 31. References in this annual report to a fiscal operations from period to period without regard to our financing methods or year, such as “fiscal year 2018,” relate to our fiscal year ended on December 31 capital structure. We exclude the items listed above from profit for the period in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, or unrealized gains in commodity risk management contracts, none of which are components of Adjusted EBITDA. Our computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year, see Note 6 to our Consolidated Financial Statements as of and for the years ended 2018, 2017 and 2016. of that calendar year. 36 GeoPark 20F Oil and gas reserves and production information Rounding DeGolyer and MacNaughton 2018 Year-end Reserves Report We have made rounding adjustments to some of the figures included The information included elsewhere in this annual report regarding estimated elsewhere in this annual report. Accordingly, numerical figures shown as quantities of proved reserves in Colombia, Chile, Brazil, Argentina and Peru totals in some tables may not be an arithmetic aggregation of the figures that is derived, in part, from estimates of the proved reserves as of December 31, precede them. 2018. The reserves estimates described herein are derived from the DeGolyer and MacNaughton Reserves Report (“D&M Reserves Report”), which was prepared for us by the independent reserves engineering team of DeGolyer and MacNaughton and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in the Fell, Campanario, Flamenco and Isla Norte Blocks in Chile, Llanos 32, Llanos 34, Yamú and La Cuerva Blocks in Colombia, BCAM-40 (Manati) in Brazil, Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina and the Morona Block in Peru. Market share and other information Market data, other statistical information, information regarding recent developments in Chile, Colombia, Brazil, Peru and Argentina and certain industry forecast data used in this annual report were obtained from internal reports and studies, where appropriate, as well as estimates, market research, publicly available information and industry publications. Industry publications generally state that the information they include has been obtained from sources believed to be reliable, but that the accuracy and completeness of such information is not guaranteed. Similarly, internal reports and studies, estimates and market research, which we believe to be reliable and accurately extracted by us for use in this annual report, have not been independently verified. However, we believe such data is accurate and agree that we are responsible for the accurate extraction of such information from such sources and its correct reproduction in this annual report. In addition, we have provided definitions for certain industry terms used in this annual report in the “Glossary of oil and natural gas terms” included as Appendix A to this annual report. GeoPark 37 Forward-looking Statements This annual report contains statements that constitute forward-looking for energy; statements. Many of the forward-looking statements contained in this • the direct or indirect impact on our business resulting from terrorist annual report can be identified by the use of forward-looking words such incidents or responses to such incidents, including the effect on the as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” availability of and premiums on insurance; and “estimate” and “potential,” among others. • other factors discussed under “Item 3. Key Information—D. Risk factors” in Forward-looking statements appear in a number of places in this annual this annual report. report and include, but are not limited to, statements regarding our intent, Forward-looking statements speak only as of the date they are made, and we belief or current expectations. Forward-looking statements are based on do not undertake any obligation to update them in light of new information or our management’s beliefs and assumptions and on information currently future developments or to release publicly any revisions to these statements available to our management. Such statements are subject to risks and in order to reflect later events or circumstances or to reflect the occurrence of uncertainties, and actual results may differ materially from those expressed unanticipated events. or implied in the forward-looking statements due to various factors, including, but not limited to, those identified under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties include factors relating to: • the volatility of oil and natural gas prices; • operating risks, including equipment failures and the amounts and timing of revenues and expenses; • termination of, or intervention in, concessions, rights or authorizations granted by the Chilean, Colombian, Brazilian, Peruvian and Argentine governments to us; • uncertainties inherent in making estimates of our oil and natural gas data; • environmental constraints on operations and environmental liabilities arising out of past or present operations; • discovery and development of oil and natural gas reserves; • project delays or cancellations; • financial market conditions and the results of financing efforts; • political, legal, regulatory, governmental, administrative and economic conditions and developments in the countries in which we operate; • fluctuations in inflation and exchange rates in Colombia, Chile, Brazil, Argentina, Peru and in other countries in which we may operate in the future; • availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services; • contract counterparty risk; • projected and targeted capital expenditures and other cost commitments and revenues; • weather and other natural phenomena; • the impact of recent and future regulatory proceedings and changes, changes in environmental, health and safety and other laws and regulations to which our company or operations are subject, as well as changes in the application of existing laws and regulations; • current and future litigation; • our ability to successfully identify, integrate and complete pending or future acquisitions and dispositions; • our ability to retain key members of our senior management and key technical employees; • competition from other similar oil and natural gas companies; • market or business conditions and fluctuations in global and local demand 38 GeoPark 20F PART I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS The selected historical financial data set forth in this section does not include any results or other financial information of any acquisitions prior to their A. Directors and senior management incorporation into our financial statements. Not applicable. B. Advisers Not applicable. C. Auditors Not applicable. ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE A. Offer statistics Not applicable. B. Method and expected timetable Not applicable. ITEM 3. KEY INFORMATION A. Selected financial data We have derived our selected historical balance sheet data as of December 31, 2018 and 2017 and our consolidated statement of income and cash flow data for the years ended December 31, 2018, 2017 and 2016 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, 2016, 2015, and 2014 and our consolidated statement of income and cash flow data for the years ended December 31, 2015 and 2014 from our consolidated financial statements not included in this annual report. During 2015, 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 2014 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. GeoPark 39 Consolidated Statement of income data For the year ended December 31, (in thousands of US$, except per share numbers) 2018 2017 2016 2015 2014 Revenue Net oil sales Net gas sales Net revenue Commodity risk management contracts Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful exploration efforts Impairment loss reversed/(recognized) for non-financial assets Other operating expense Operating profit (loss) Financial costs Foreign exchange (loss) gain Profit (Loss) before tax Income tax (expense) benefit Profit (Loss) for the year Non-controlling interest Profit (Loss) attributable to owners of the Company Earnings (Losses) per share for profit attributable to owners of the Company—Basic Earnings (Losses) per share for profit attributable to owners of the Company—Diluted Weighted average common shares outstanding—Basic Weighted average common shares outstanding—Diluted 545,490 55,671 601,161 16,173 (174,260) (13,951) (52,074) (4,023) (92,240) (26,389) 4,982 (2,887) 256,492 (36,262) (11,323) 208,907 (106,240) 102,667 30,252 72,415 1.19 1.11 279,162 50,960 330,122 (15,448) (98,987) (7,694) (42,054) (1,136) (74,885) (5,834) - (5,088) 78,996 (51,495) (2,193) 25,308 (43,145) (17,837) 6,391 (24,228) 145,193 47,477 192,670 (2,554) (67,235) (10,282) (34,170) (4,222) (75,774) (31,366) 5,664 (1,344) 162,629 47,061 209,690 - (86,742) (13,831) (37,471) (5,211) (105,557) (30,084) (149,574) (13,711) (28,613) (232,491) (34,101) 13,872 (48,842) (35,655) (33,474) (301,620) (11,804) (60,646) 17,054 (284,566) (11,554) (49,092) (50,535) (234,031) (0.40) (0.82) (4.05) (0.40) (0.82) (4.05) 367,102 61,632 428,734 - (131,419) (13,002) (45,867) (24,428) (100,528) (30,367) (9,430) (1,849) 71,844 (27,622) (23,097) 21,125 (5,195) 15,930 7,845 8,085 0.14 0.14 60,612,230 60,093,191 59,777,145 57,759,001 56,396,812 65,370,782 60,093,191 59,777,145 57,759,001 58,840,412 Common Shares outstanding at year-end 60,483,447 60,596,219 59,940,881 59,535,614 57,790,533 40 GeoPark 20F Balance sheet data As of December 31, (In thousands of US$) Assets Non-current assets Property, plant and equipment Prepaid taxes Other financial assets Deferred income tax Prepayments and other receivables Total non-current assets Current assets Other financial assets Inventories Trade receivables Prepayments and other receivables Prepaid taxes Derivative financial instrument assets Cash and cash equivalents Assets held for sale Total current assets Total assets Share capital Share premium Other Equity attributable to owners of the Company Equity attributable to non-controlling interest Total equity Liabilities Non-current liabilities Borrowings Provisions for other long-term liabilities Trade and other payables Deferred income tax Total non-current liabilities Current liabilities Borrowings Derivative financial instrument liabilities Current income tax Trade and other payables Liabilities associated with assets held for sale Total current liabilities Total liabilities 2018 2017 2016 2015 2014 557,170 517,403 473,646 522,611 790,767 3,275 10,570 31,793 219 3,823 22,110 27,636 235 2,852 19,547 23,053 241 1,172 13,306 34,646 220 1,253 12,979 33,195 349 603,027 571,207 519,339 571,955 838,543 898 9,309 16,215 9,489 45,170 27,539 127,727 23,286 259,633 862,660 60 237,840 (94,879) 143,021 – 21,378 5,738 19,519 7,518 26,048 - 134,755 - 214,956 786,163 61 239,191 (154,327) 84,925 41,915 143,021 126,840 2,480 3,515 18,426 7,402 15,815 - 73,563 - 121,201 640,540 60 236,046 (130,341) 105,765 35,828 141,593 429,027 42,577 14,789 14,801 418,540 46,284 25,921 2,286 319,389 42,509 34,766 2,770 1,118 4,264 13,480 11,057 19,195 - - 8,532 36,917 13,993 13,459 - 82,730 127,672 - 131,844 703,799 59 232,005 (85,412) 146,652 53,515 200,167 343,248 42,450 19,556 16,955 - 200,573 1,039,116 58 210,886 164,613 375,557 103,569 479,126 342,440 46,910 16,583 30,065 501,194 493,031 399,434 422,209 435,998 17,975 - 58,776 131,420 10,274 218,445 719,639 7,664 19,289 42,942 96,397 - 166,292 659,323 39,283 3,067 5,155 52,008 - 99,513 498,947 35,425 - 208 45,790 - 81,423 503,632 27,153 - 7,935 88,904 - 123,992 559,990 Total equity and liabilities 862,660 786,163 640,540 703,799 1,039,116 GeoPark 41 Cash flow data For the year ended December 31, (In thousands of US$) Cash provided by (used in) Operating activities Investing activities Financing activities Net (decrease) increase in cash and cash equivalents Other financial data 2018 2017 2016 2015 2014 256,206 (164,594) (97,641) (6,029) 142,158 (105,604) 23,968 60,522 82,884 (39,306) (51,136) (7,558) 25,895 (48,842) (18,022) (40,969) 230,746 (344,041) 124,716 11,421 For the year ended December 31, 2018 2017 2016 2015 2014 Adjusted EBITDA(1) (US$ thousands) Adjusted EBITDA margin(2) Adjusted EBITDA per boe(3) 330,556 55.0% 26.5 175,776 53.2% 18.4 78,321 40.6% 10.2 73,787 35.2% 10.5 220,077 51.3% 33.0 (1) Adjusted EBITDA is a non-IFRS financial measure. For a definition of Adjusted EBITDA and other information relating to this measure, see “Presentation of Financial and Other Information—Financial statements— Non-IFRS financial measures.” For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year, see Note 6 to our Consolidated Financial Statements. (2) Adjusted EBITDA margin is defined as Adjusted EBITDA divided by net revenue. (3) Adjusted EBITDA per boe is defined as Adjusted EBITDA divided by total boe. 42 GeoPark 20F Exchange rates In Colombia, Chile, Argentina and Peru, our functional currency is the U.S. The prices that we receive for our oil and natural gas production heavily dollar. In Brazil, our functional currency is the real. influence our revenues, profitability, access to capital and growth rate. Historically, the markets for oil, natural gas and methanol (which have Our operations in Brazil accounted for 12% and 8% of our consolidated assets influenced prices for almost all of our Chilean gas sales) have been volatile and and 10% and 5% of our revenues for the years ended December 31, 2017 will likely continue to be volatile in the future. International oil, natural gas and and 2018, respectively. This portion of our business is exposed to losses that methanol prices have fluctuated widely in recent years and may continue to may arise from currency fluctuation, as a significant amount of our revenues, do so in the future. operating costs, administrative expenses and taxes in Brazil are denominated in reais. The prices that we will receive for our production and the levels of our production depend on numerous factors beyond our control. These factors The real may depreciate or appreciate substantially against the U.S. dollar. include, but are not limited, to the following: We recorded exchange rate losses amounting to US$5.9 million for the year ended December 31, 2018, principally due to the devaluation of the real • global economic conditions; and its impact on US dollar denominated intercompany debt cancelled by • changes in global supply and demand for oil, natural gas and methanol; our Brazilian subsidiary in October 2018. We recorded exchange rate losses • the actions of the Organization of the Petroleum Exporting Countries amounting to US$1.3 million for the year ended December 31, 2017 as a result (“OPEC”); of the devaluation of the local currency in our Brazilian subsidiary which was • political and economic conditions, including embargoes, in oil-producing mainly generated by the credit facility with Itaú BBA International plc that countries or affecting other countries; we incurred on March 31, 2014 to acquire Rio das Contas, which we repaid in • the level of oil- and natural gas-producing activities, particularly in the September 2017. See “—D. Risk factors—Risks relating to our business—Our Middle East, Africa, Russia, South America and the United States; results of operations could be materially adversely affected by fluctuations in • the level of global oil and natural gas exploration and production activity; foreign currency exchange rates.” • the level of global oil and natural gas inventories; Exchange rate fluctuation may affect the US$ value of any distributions we • availability of markets for natural gas; make with respect to our common shares. See “—D. Risk factors—Risks • weather conditions and other natural disasters; relating to our business—Our results of operations could be materially • technological advances affecting energy production or consumption; adversely affected by fluctuations in foreign currency exchange rates.” • domestic and foreign governmental laws and regulations, including • the price of methanol; B. Capitalization and indebtedness Not applicable. environmental, health and safety laws and regulations; • proximity and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas in C. Reasons for the offer and use of proceeds captive market areas; Not applicable. D. Risk factors • quality discounts for oil production based, among other things, on API, sulphur and mercury content; • taxes and royalties under relevant laws and the terms of our contracts; Our business, financial condition and results of operations could be materially • our ability to enter into oil and natural gas sales contracts at fixed prices; and adversely affected if any of the risks described below occur. As a result, • the level of global methanol demand and inventories and changes in the the market price of our common shares could decline, and you could lose all uses of methanol; or part of your investment. This annual report also contains forward-looking • the price and availability of alternative fuels; and statements that involve risks and uncertainties. See “Forward-Looking • future changes to our hedging policies. 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 These factors and the volatility of the energy markets make it extremely may also adversely affect us. Risks relating to our business 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, 2014 to December 31, 2018, Brent spot prices ranged from a low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub A substantial or extended decline in oil, natural gas and methanol prices natural gas average spot prices ranged from a low of US$1.7 per mmbtu to may materially adversely affect our business, financial condition or results a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged of operations. GeoPark 43 Risk factors from a low of US$250.0 per metric ton to a high of US$635.1 per metric See Note 8 to our Consolidated Financial Statements for details regarding ton. Furthermore, oil, natural gas and methanol prices do not necessarily Commodity Risk Management Contracts. fluctuate in direct relationship to each other. For the year ended December 31, 2018, 91% of our revenues were derived from oil. Because we expect that our production mix will continue to be We face limitations on our ability to increase prices or improve ma rgins weighted towards oil, our financial results are more sensitive to movements on the oil and natural gas that we sell. As a consequence of the oil price The oil price crisis has impacted our operations and corporate strategy. in oil prices. 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 As of December 31, 2018, natural gas comprised 9% of our revenues. A and March 2016), the Company took decisive measures to ensure its ability decline in natural gas prices could negatively affect our future growth, to both maximize ongoing projects and to preserve its cash. particularly for future gas sales where we may not be able to secure or extend our current long-term contracts. Funding our anticipated capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to Lower oil and natural gas prices may impact our revenues on a per unit generate sufficient cash flow. Low oil prices affect our revenues, which basis, and may also reduce the amount of oil and natural gas that can in turn affect our debt capacity and the covenants in our financing be produced economically. In addition, changes in oil and natural gas agreements, as well as the amount of cash we can borrow using our oil prices can impact the valuation of our reserves and, in periods of lower reserves as collateral, the amount of cash we are able to generate from commodity prices, we may curtail production and capital spending or may current operations and the amount of cash we can obtain from prepayment defer or delay drilling wells because of lower cash generation. Lower oil agreements. If we are not able to generate the sales which, together with and natural gas prices could also affect our growth, including future and our current cash resources, are sufficient to fund our capital program, we pending acquisitions. A substantial or extended decline in oil or natural gas will not be able to efficiently execute our work program, which would cause prices could adversely affect our business, financial condition and results of us to further decrease our work program and would harm our business operations. outlook, investor confidence and our share price. For example, during 2014 and 2015, we evaluated the recoverability of our In addition, actions taken by the company to maximize ongoing projects fixed assets affected by the oil price decline and recorded an impairment and to reduce expenses, including renegotiations and reduction of oil of non-financial assets amounting to, respectively, US$9.4 million and and gas service contracts and other initiatives such as cost cutting may US$149.6 million. US$5.7 million of the impairment recorded in 2015 was expose us to claims and contingencies from interested parties that may reversed in 2016 due to increased estimated market prices for 2017 and have a negative impact on our business, financial condition, results of 2018 and improvements in cost structure. After conducting an impairment operations and cash flows. If oil prices are lower than expected, we may be test procedure for the year ended December 31, 2018 we recognized US$ unable to meet our contractual obligations with oil and service contracts 11.5 million as reversal of impairment losses due to increases in estimated and our suppliers. Equally, those third parties may be unable to meet their market prices and improvements in cost structure, and also the known fair contractual obligations to us as a result of the oil price crisis, impacting on value less costs of disposal of the La Cuerva and Yamu Blocks in Colombia, our operations. partially offset by an impairment loss in Chile of US$ 6.5 million due to the termination of the sales agreement for the TdF’s blocks, with no renovation In budgeting for our future activities, we have relied on a number of in place as of the date of this annual report. See Note 36 to our Consolidated assumptions, including, with regard to our discovery success rate, the Financial Statements for details regarding oil price scenarios, discount rates number of wells we plan to drill, our working interests in our prospects, considered and sensitivity analysis affecting the impairment charges. 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 Continuing our hedging strategy, we entered into derivative financial financing with respect to any further acquisitions and the availability of instruments to manage exposure to oil price risk. These derivatives were both suitable equipment and qualified personnel. These assumptions are zero-premium collars or zero premium three way hedges (put, spread and inherently subject to significant business, political, economic, regulatory, call) and were placed with major financial institutions and commodity environmental and competitive uncertainties, conditions in the financial traders. We entered into the derivatives under ISDA Master Agreements markets, contingencies and risks, all of which are difficult to predict and and Credit Support Annexes, which provide credit lines for collateral many of which are beyond our control. In addition, we opportunistically posting thus alleviating possible liquidity needs under the instruments and seek out new assets and acquisition targets to complement our existing protecting us from potential non-performance risk by our counterparties. operations and have financed such acquisitions in the past through 44 GeoPark 20F the incurrence of additional indebtedness, including additional bank and our business, financial condition and results of operations will be credit facilities, equity issuances or the sale of minority stakes in certain materially adversely affected. 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 We derive a significant portion of our revenues from sales to a few key choose to expand our hydrocarbon asset acquisition, exploration, appraisal customers. or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the In Colombia, for the year ended December 31, 2018, we made 99% of our oil conditions for raising capital are favorable. The ultimate amount of capital sales from operated blocks to C.I. Trafigura Petroleum Colombia S.A.S., a leading that we will expend may fluctuate materially based on market conditions, commodity trading and logistics company (“Trafigura”), representing 82% of our continued production, decisions by the operators in blocks where our consolidated revenues for the same period. Considering the expiration we are not the operator, the success of our drilling results and future of our long-term contract with Trafigura in December 2018, we have started acquisitions. Our future financial condition and liquidity will be impacted diversifying our client base in Colombia, allocating sales on a competitive basis by, among other factors, our level of production of oil and natural gas and to leading industry participants including traders and other producers. The the prices we receive from the sale thereof, the success of our exploration contracts extend through 2019 with no long-term delivery commitments in and appraisal drilling program, the number of commercially viable oil place. Delivery points include wellhead and other locations in the Colombian and natural gas discoveries made and the quantities of oil and natural pipeline system. We manage the counterparty credit risk associated to sales gas discovered, the speed with which we can bring such discoveries to contracts by including early payment conditions which minimize our exposure. production and the actual cost of exploration, appraisal and development of our oil and natural gas assets. In Chile, 100% of our crude oil and condensate sales are made to ENAP. For the year ended December 31, 2018, sales to ENAP represented 3% of our Unless we replace our oil and natural gas reserves, our reserves and total revenues. ENAP imports the majority of the oil it refines and partially production will decline over time. Our business is dependent on our supplements those imports with volumes supplied locally by its own operated continued successful identification of productive fields and prospects and fields and those operated by us. On April 21, 2017, we renewed our sales the identified locations in which we drill in the future may not yield oil or agreement with ENAP. As part of this agreement, ENAP has committed to natural gas in commercial quantities. purchase our oil production in the Fell Block in the amounts that we produce, subject to the limitation of available storage capacity at the Gregorio Terminal. Production from oil and gas properties declines as reserves are depleted, The sales agreement provides us with the option to interrupt sales to ENAP with the rate of decline depending on reservoir characteristics. Accordingly, periodically if conditions in the export markets allow for more competitive our current proved reserves will decline as these reserves are produced. As price levels. While the agreement renews automatically on an annual basis, of December 31, 2018, our reserves-to-production (or reserve life) ratio for we typically make an annual revision jointly with ENAP. In addition, for the net proved reserves in Colombia, Chile, Argentina, Brazil and Peru was 8.2 year ended December 31, 2018, almost all of our natural gas sales in Chile years. According to estimates, if on January 1, 2019 we ceased all drilling were made to Methanex Chile SpA., the Chilean subsidiary of the Methanex and development activities, including recompletions, refracs and workovers, Corporation (“Methanex”), a leading global methanol producer, under a long- our proved developed producing reserves base in Colombia, Chile, Brazil, term contract (the “Methanex Gas Supply Agreement”), which will expire on Argentina and Peru would decline 34% during the first year. December 31, 2026. Sales to Methanex represented 3% of our consolidated revenues for the year ended December 31, 2018. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently In Brazil, all of our gas and condensate produced in the Manati Field is sold to developing our current reserves and using cost-effective methods to find Petróleo Brasileiro S.A. (“Petrobras”), the operator of the Manati Field, pursuant or acquire additional recoverable reserves. While we have had success in to a long-term gas off-take contract and a condensate purchase agreement. identifying and developing commercially exploitable fields and drilling See “Item 4. Information on the Company—B. Business Overview—Significant locations in the past, we may be unable to replicate that success in the Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.” future. We may not identify any more commercially exploitable fields or successfully drill, complete or produce more oil or gas reserves, and the In Argentina, all the gas produced in 2018 was sold to Grupo Albanesi, a leading wells which we have drilled and currently plan to drill within our blocks or Argentine privately held conglomerate focused on the energy market that concession areas may not discover or produce any further oil or gas or may offers natural gas and power supply and transport services to its customers. not discover or produce additional commercially viable quantities of oil or We have an annual agreement effective from May 2018 through April 2019. gas to enable us to continue to operate profitably. If we are unable to replace Gas sales in Argentina represented 1% of our total revenue. The oil sales in our current and future production, the value of our reserves will decrease, Argentina are diversified across clients and delivery points: i) 30% of the oil GeoPark 45 produced in Argentina (2% of our total revenue) is sold locally in Neuquén our business, financial condition and results of operations. Province, delivered at well-head; and ii) 70% of the oil produced in Argentina (3% of our total revenues) is sold to major Argentine refineries, and delivered There are inherent risks and uncertainties relating to the exploration and via pipeline. production of oil and natural gas. If any of our buyers were to decrease or cease purchasing oil or gas from us, Our performance depends on the success of our exploration and or if any of them were to decide not to renew their contracts with us or to production activities and on the existence of the infrastructure that will renew them at a lower sales price, this could have a material adverse effect on allow us to take advantage of our oil and gas reserves. Oil and natural our business, financial condition and results of operations. For example, see gas exploration and production activities are subject to numerous risks “Item 4. Information on the Company—B. Business Overview—Significant beyond our control, including the risk that exploration activities will not Agreements—Colombia” and “Item 4. Information on the Company—B. identify commercially viable quantities of oil or natural gas. Our decisions Business Overview—Significant Agreements—Chile.” to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of seismic and other data obtained Our results of operations could be materially adversely affected by through geophysical, geochemical and geological analysis, production fluctuations in foreign currency exchange rates. data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Although a majority of our net revenues is denominated in US$, unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Furthermore, the marketability of any oil and natural gas production from Colombia, Chile, Brazil, Argentina and Peru could have a material adverse effect our projects may be affected by numerous factors beyond our control. on our results of operations. A portion of the cost reductions that we achieved These factors include, but are not limited to, proximity and capacity of in 2015 and 2016 (as compared to 2014) were related to the depreciation of pipelines and other means of transportation, the availability of upgrading local currencies, including mainly the Col$, the Ch$ and the Brazilian real. An and processing facilities, equipment availability and government laws and appreciation of local currencies can increase our costs and negatively impact regulations (including, without limitation, laws and regulations relating to our results from operations. prices, sale restrictions, taxes, governmental stake, allowable production, importing and exporting of oil and natural gas, environmental protection Because our Consolidated Financial Statements are presented in US$, we must and health and safety). The effect of these factors, individually or jointly, translate revenues, expenses and income, as well as assets and liabilities, into cannot be accurately predicted, but may have a material adverse effect on US$ at exchange rates in effect during or at the end of each reporting period. In our business, financial condition and results of operations. December 2018, we decided to manage exposure to local currency fluctuation with respect to income tax balances in Colombia. Consequently, we entered There can be no assurance that our drilling programs will produce oil into a derivative financial instrument with a local bank in Colombia, for an and natural gas in the quantities or at the costs anticipated, or that our amount equivalent to US$ 92.1 million, in order to anticipate any currency currently producing projects will not cease production, in part or entirely. fluctuation with respect to estimated income taxes to be paid during the first Drilling programs may become uneconomic as a result of an increase in half of 2019. 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 Through our Brazilian operations, we are exposed to fluctuations in the for our oil and natural gas production may differ materially from current real against the US$, as our Brazilian revenues and expenses are mostly estimates. In addition, even if we are able to continue to produce oil and denominated in reais. In the past, the Brazilian Central Bank has occasionally gas, there can be no assurance that we will have the ability to market our oil intervened to control unstable movements in foreign exchange rates. We and gas production. See “—Our inability to access needed equipment and cannot predict whether the Brazilian Central Bank or the Brazilian government infrastructure in a timely manner may hinder our access to oil and natural will continue to permit the real to float freely or will intervene in the exchange gas markets and generate significant incremental costs or delays in our oil rate market through the return of a currency band system or otherwise. and natural gas production” below. Furthermore, Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments or there are reasons to foresee a serious Our identified potential drilling location inventories are scheduled over imbalance, temporary restrictions may be imposed on remittances of foreign many years, making them susceptible to uncertainties that could materially capital abroad. We cannot assure you that such measures will not be taken by alter the occurrence or timing of their drilling. the Brazilian government in the future. The real has experienced frequent and substantial variations in relation to the US$ and other foreign currencies, which Our management team has specifically identified and scheduled certain could materially and adversely affect the growth of the Brazilian economy and potential drilling locations as an estimation of our future multi-year drilling 46 GeoPark 20F activities on our existing acreage. These identified potential drilling locations, Oil and gas operations contain a high degree of risk and we may not be fully including those without proved undeveloped reserves, represent a significant insured against all risks we face in our business. part of our growth strategy. Oil and gas exploration and production is speculative and involves a high Our ability to drill and develop these identified potential drilling locations degree of risk and hazards. In particular, our operations may be disrupted depends on a number of factors, including oil and natural gas prices, the by risks and hazards that are beyond our control and that are common availability and cost of capital, drilling and production costs, the availability among oil and gas companies, including environmental hazards, blowouts, of drilling services and equipment, drilling results, lease expirations, the industrial accidents, occupational safety and health hazards, technical availability of gathering systems, marketing and transportation constraints, failures, labor disputes, community protests or blockades, unusual or refining capacity, regulatory approvals and other factors. Because of the unexpected geological formations, flooding, earthquakes and extended uncertainty inherent in these factors, there can be no assurance that the interruptions due to weather conditions, explosions and other accidents. 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 While we believe that we maintain customary insurance coverage for other potential drilling locations. 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 Our business requires significant capital investment and maintenance may contain significant exclusions from and limitations on coverage. We expenses, which we may be unable to finance on satisfactory terms or at all. 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 Because the oil and natural gas industry is capital intensive, we expect to presented. The occurrence of a significant event or a series of events against make substantial capital expenditures in our business and operations for which we are not fully insured and any losses or liabilities arising from the exploration and production of oil and natural gas reserves. See “Item 4. uninsured or underinsured events could have a material adverse effect on Information on the Company –B. Business Overview—2019 Strategy and our business, financial condition or results of operations. Outlook.” We incurred capital expenditures of US$125 million and US$106 million during the years ended December 31, 2018 and 2017, respectively. The development schedule of oil and natural gas projects is subject to cost See “Item 5. Operating and Financial Review and Prospects—A. Operating overruns and delays. Results—Factors Affecting our Results of Operations—Discovery and exploitation of reserves.” Oil and natural gas projects may experience capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling The actual amount and timing of our future capital expenditures may differ rigs and other essential equipment, supplies, personnel and oil field services. materially from our estimates as a result of, among other things, commodity The cost to execute projects may not be properly established and remains prices, actual drilling results, the availability of drilling rigs and other dependent upon a number of factors, including the completion of detailed equipment and services, and regulatory, technological and competitive cost estimates and final engineering, contracting and procurement costs. developments. In response to changes in commodity prices, we may increase Development of projects may be materially adversely affected by one or more or decrease our actual capital expenditures. We intend to finance our future of the following factors: capital expenditures through cash generated by our operations and potential • shortages of equipment, materials and labor; future financing arrangements. However, our financing needs may require • fluctuations in the prices of construction materials; us to alter or increase our capitalization substantially through the issuance of • delays in delivery of equipment and materials; debt or equity securities or the sale of assets. • labor disputes; • political events; If our capital requirements vary materially from our current plans, we may • title problems; require further financing. In addition, we may incur significant financial • obtaining easements and rights of way; indebtedness in the future, which may involve restrictions on other financing • blockades or embargoes; and operating activities. We may also be unable to obtain financing or • litigation; financing on terms favorable to us. These changes could cause our cost • compliance with governmental laws and regulations, including of doing business to increase, limit our ability to pursue acquisition environmental, health and safety laws and regulations; opportunities, reduce cash flow used for drilling and place us at a competitive • adverse weather conditions; disadvantage. A significant reduction in cash flows from operations or the • unanticipated increases in costs; availability of credit could materially adversely affect our ability to achieve our • natural disasters; planned growth and operating results. • accidents; GeoPark 47 • transportation; Our estimated oil and gas reserves are based on assumptions that may • unforeseen engineering and drilling complications; prove inaccurate. • environmental or geological uncertainties; and • other unforeseen circumstances. Our oil and gas reserves estimates in Colombia, Chile, Argentina, Brazil, and Peru as of December 31, 2018 are based on the D&M Reserves Report. Any of these events or other unanticipated events could give rise to delays in Although classified as “proved reserves,” the reserves estimates set forth in development and completion of our projects and cost overruns. the D&M Reserves Reports are based on certain assumptions that may prove For example, in 2017, the drilling and completion cost for the exploratory well in estimates included oil and gas sales prices determined according to SEC Río Grande Oeste x-1 in our CN-V Block in Argentina was originally estimated guidelines, future expenditures and other economic assumptions (including at US$4.2 million, but the actual cost was US$5.5 million, mainly due to interests, royalties and taxes) as provided by us. mechanical issues related to failures with an electric submersible pump, as well as testing of additional formations which had not been budgeted. Oil and gas reserves engineering is a subjective process of estimating inaccurate. DeGolyer and MacNaughton’s primary economic assumptions accumulations of oil and gas that cannot be measured in an exact way, Delays in the construction and commissioning of projects or other technical and estimates of other engineers may differ materially from those set out difficulties may result in future projected target dates for production being herein. Numerous assumptions and uncertainties are inherent in estimating delayed or further capital expenditures being required. These projects quantities of proved oil and gas reserves, including projecting future rates of may often require the use of new and advanced technologies, which can production, timing and amounts of development expenditures and prices of be expensive to develop, purchase and implement and may not function oil and gas, many of which are beyond our control. Results of drilling, testing as expected. Such uncertainties and operating risks associated with and production after the date of the estimate may require revisions to be development projects could have a material adverse effect on our business, made. For example, if we are unable to sell our oil and gas to customers, this results of operations or financial condition. may impact the estimate of our oil and gas reserves. Accordingly, reserves Competition in the oil and natural gas industry is intense, which makes it are ultimately recovered, and if such recovered quantities are substantially difficult for us to attract capital, acquire properties and prospects, market lower than the initial reserves estimates, this could have a material adverse oil and natural gas and secure trained personnel. impact on our business, financial condition and results of operations. estimates are often materially different from the quantities of oil and gas that We compete with the major oil and gas companies engaged in the exploration Our inability to access needed equipment and infrastructure in a timely and production sector, including state-owned exploration and production manner may hinder our access to oil and natural gas markets and generate companies that possess substantially greater financial and other resources significant incremental costs or delays in our oil and natural gas production. than we do for researching and developing exploration and production technologies and access to markets, equipment, labor and capital required Our ability to market our oil and natural gas production depends substantially to acquire, develop and operate our properties. We also compete for the on the availability and capacity of processing facilities, oil tankers, acquisition of licenses and properties in the countries in which we operate. transportation facilities (such as pipelines, crude oil unloading stations and trucks) and other necessary infrastructure, which may be owned and operated Our competitors may be able to pay more for productive oil and natural by third parties. Our failure to obtain such facilities on acceptable terms or gas properties and exploratory prospects and to evaluate, bid for and on a timely basis could materially harm our business. We may be required to purchase a greater number of properties and prospects than our financial or shut down oil and gas wells because access to transportation or processing personnel resources permit. Our competitors may also be able to offer better facilities may be limited or unavailable when needed. If that were to occur, then compensation packages to attract and retain qualified personnel than we are we would be unable to realize revenue from those wells until arrangements able to offer. In addition, there is substantial competition for capital available were made to deliver the production to market, which could cause a material for investment in the oil and natural gas industry. As a result of each of the adverse effect on our business, financial condition and results of operations. aforementioned, we may not be able to compete successfully in the future in In addition, the shutting down of wells can lead to mechanical problems acquiring prospective reserves, developing reserves, marketing hydrocarbons, upon bringing the production back on line, potentially resulting in decreased attracting and retaining quality personnel or raising additional capital, which production and increased remediation costs. The exploitation and sale of oil could have a material adverse effect on our business, financial condition or and natural gas and liquids will also be subject to timely commercial processing results of operations. See “Item 4. Information on the Company—B. Business and marketing of these products, which depends on the contracting, financing, Overview—Our competition.” building and operating of infrastructure by third parties. 48 GeoPark 20F In Colombia, producers of crude oil have historically suffered from tanker In addition, as the Morona Block is located in a remote area of the tropical transportation logistics issues and limited pipeline and storage capacity, which rainforest, the development of the project involves significant infrastructure cause delays in delivery and transfer of title of crude oil. Such capacity issues to be built, including processing facilities, storages tanks and a 37 kilometers- in Colombia may require us to transport crude from our Colombian operations long flexible pipeline which is required to start production. In addition, the full via truck, which may increase the costs of those operations. Road infrastructure development of the project would require a 97 kilometers-long pipeline from is limited in certain areas in which we operate, and certain communities have the site to the North Peruvian Pipeline. Also, as there are no roads available used and may continue to use road blockages, which can sometimes interfere in the surrounding area, logistics will be performed by helicopters or barges. with our operations in these areas. For example, in 2018, the main delivery These issues may lead us to incur significant costs or investments that may not point for the Colombian production was Oleoducto de Los Llanos “ODL.” During be recoverable through our commercial activities in the Morona Block.  the last week of July 2018, the operation of the Ocensa Pipeline, which receives oil flow from the ODL Pipeline, was disrupted because of a contingency. In Argentina, we deliver a portion of our oil production and all of our gas Although we were able to enable alternative delivery points and transport oil production via existing pipeline infrastructure controlled by third parties. by trucks, avoiding any negative impact in our production during this period, While both the oil and gas pipeline systems in Argentina are well-developed we cannot assure we would be able to do so in the future. and have operated reliably in the past, we cannot guarantee this will continue In Chile, we transport the crude oil we produce in the Fell Block by truck to may become insufficient. We also deliver a portion of our crude production ENAP’s processing, storage and selling facilities at the Gregorio Refinery. at well-head. This volume is lifted from our loading facilities by third-party As of the date of this annual report, ENAP purchases all of the crude oil we operated trucks contracted by our clients. The roads around our fields are in produce in Chile. We rely upon the continued good condition, maintenance good condition but changes in those conditions could adversely affect our and accessibility of the roads we use to deliver the crude oil we produce. If operations. Our failure to secure transportation or access to pipelines or other the condition of these roads were to deteriorate or if they were to become facilities on acceptable terms or on a timely basis could materially harm our in the future. In addition, as Argentina’s production grows, pipeline capacity inaccessible for any period of time, this could delay delivery of crude oil in Chile business. and materially harm our business. Through our Brazilian operations, we face operational risks relating to In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas offshore drilling. we produce to Methanex, the principal purchaser of the gas we produce. If ENAP’s pipelines were unavailable, this could have a materially adverse effect Our operations in the BCAM-40 Concession in Brazil may include shallow- on our ability to deliver and sell our product to Methanex, which could have a offshore drilling activity in one area in the Camamu-Almada Basin, which we material adverse effect on our gas sales. In addition, gas production in some expect will continue to be operated by Petrobras. areas in the Tierra del Fuego Blocks and the Tranquilo Block could require us in the future to build a new network of gas pipelines in order for us to be able Offshore operations are subject to a variety of operating risks and laws and to deliver our product to market, which could require us to make significant regulations, including among other things, with respect to environmental, capital investments. health and safety matters, specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse While Brazil has a well-developed network of hydrocarbon pipelines, storage weather conditions. These conditions can cause substantial damage to and loading facilities, we may not be able to access these facilities when facilities and interrupt production. As a result, we could incur substantial needed. Pipeline facilities in Brazil are often full and seasonal capacity liabilities, compliance costs, fines or penalties that could reduce or eliminate restrictions may occur, particularly in natural gas pipelines. Our failure to secure the funds available for exploration, development or leasehold acquisitions, or transportation or access to pipelines or other facilities once we commence result in loss of equipment and properties. For example, the Manati Field has operations in the concessions we were awarded in Brazil on acceptable terms been subject to administrative infraction notices, which have resulted in fines or on a timely basis could materially harm our business. against Petrobras in an aggregate amount of approximately US$12 million, In Peru, future production in the Morona Block is expected to be transported Environment and Natural Renewable Resources (Instituto Brasileiro do Meio- through the existing North Peruvian Pipeline, which was out of service in Ambiente e dos Recursos Naturais Renováveis). Although the administrative 2017 due to technical issues and presented some interruptions to service fines were filed against Petrobras, as a party to the concession agreement during 2018. Though the Peruvian government is implementing a program to governing the Manati Field, we may be liable up to our participation interest all of which are pending a final decision of the Brazilian Institute for the maintain and modernize the pipeline, future technical issues, other general of 10%. infrastructure problems or social unrest affecting pipeline operation may adversely affect the recoverability of our future investments, our future Additionally, offshore drilling generally requires more time and more production or revenues related to the Morona Block. GeoPark 49 advanced drilling technologies, involving a higher-risk of technological We may suffer delays or incremental costs due to difficulties in negotiations failure and usually higher drilling costs. Offshore projects often lack proximity with landowners and local communities, including native communities, to existing oilfield service infrastructure, necessitating significant capital where our reserves are located. investment in flow line infrastructure before we can market the associated oil or gas of a commercial discovery, increasing both the financial and operational Access to the sites where we operate requires agreements (including, risk involved with these operations. Because of the lack and high cost of for example, assessments, rights of way and access authorizations) with infrastructure, some offshore reserve discoveries may never be produced landowners and local communities. If we are unable to negotiate agreements economically. 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. Further, because we are not the operator of our offshore fields, all of these In Chile and in Argentina, for example, we have negotiated the necessary risks may be heightened since they are outside of our control. We have a agreements for many of our current operations in the Magallanes Basin, in 10% interest in the Manati Field which limits our operating flexibility in such Neuquén and in Mendoza (when we had the operatorship of the CN-V Block), offshore fields. See “—We are not, and may not be in the future, the sole owner respectively. In Brazil, in the event that social unrest continues or intensifies, or operator of all of our licensed areas and do not, and may not in the future, this may lead to delays or damage relating to our ability to operate the assets hold all of the working interests in certain of our licensed areas. Therefore, we we have acquired or may acquire in our Brazil Acquisitions. 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 In Colombia, although we have agreements with many landowners and are extent, any non-wholly-owned, assets.” in negotiations with others, we expect our costs to increase following current Our pending acquisition of the Espejo and Perico blocks in Ecuador is subject expectations of landowners have generally increased, which may delay and future negotiations regarding access to our blocks, as the economic to regulatory approvals. access to existing or future sites. In addition, the expectations and demands of local communities on oil and gas companies operating in Colombia may In March 2019, GeoPark, in consortium with Frontera (50% GeoPark, 50% also increase. As a result, local communities have demanded that oil and Frontera) was awarded the Espejo and Perico blocks in the form of production gas companies invest in remediating and improving public access roads, sharing contracts in the Intracampos Bid Round carried out on March 12, 2019 compensate them for any damages related to use of such roads and, more in Quito, Ecuador. The closing of the acquisition is subject to the occurrence of generally, invest in infrastructure that was previously paid for with public certain conditions, including obtaining other governmental approvals. Failure funds. Due to these circumstances, oil and gas companies in Colombia, to obtain such approvals may result in the termination of the agreement. We including us, are now dealing with increasing difficulties resulting from expect the transaction to close in the second quarter of 2019 but we cannot instances of social unrest, temporary road blockages and conflicts with guarantee that the regulatory approvals will be obtained by that time or that landowners. the acquisition will be completed on this timeline. There can be no assurance that disputes with landowners and local Following the eventual completion of this acquisition, conducting operations communities will not delay our operations or that any agreements we reach in Ecuador, a new jurisdiction for us, will subject us to risks that are inherent with such landowners and local communities in the future will not require us for foreign companies operating in Ecuador, including challenges posed to incur additional costs, thereby materially adversely affecting our business, by different laws and customs; lack of familiarity and burdens of complying financial condition and results of operations. Local communities may also with such foreign laws, legal standards, regulatory requirements, tariffs protest or take actions that restrict or cause their elected government to and other barriers; unexpected changes in regulatory requirements, taxes, restrict our access to the sites of our operations, which may have a material trade laws, tariffs, export quotas, custom duties or other trade restrictions; adverse effect on our operations at such sites. potential difficulties in collecting accounts receivable; difficulties in managing and staffing operations; varying expectations as to employee standards; In Peru, the Morona Block is located in land inhabited by native communities. potentially adverse tax consequences, including possible restrictions on the Though we have already signed certain agreements with native communities repatriation of earnings. Moreover, operations in Ecuador could be interrupted authorizing the execution of the environmental impact assessment for the and negatively affected by economic changes, geopolitical regional conflicts, Morona Project, which the environmental authority is currently analyzing, terrorist activity, political unrest, civil strife, acts of war and other economic or similar projects in the Peruvian rainforest have faced significant social conflicts political uncertainties. All of these risks could result in increased costs which and work delays due to community claims. Social conflicts or community could have a material adverse effect on our financial condition, results of claims could adversely affect the recoverability of our future investments, our operations and cash flows. future production and revenues related to the Morona Block. 50 GeoPark 20F Under the terms of some of our various CEOPs, E&P Contracts and A significant amount of our reserves or production have been derived from concession agreements, we are obligated to drill wells, declare any our operations in certain blocks, including the Llanos 34 Block in Colombia, discoveries and file periodic reports in order to retain our rights and the Fell Block in Chile, the BCAM-40 Concession in Brazil, the Aguada establish development areas. Failure to meet these obligations may result in Baguales Block in Argentina and the Morona Block in Peru. the loss of our interests in the undeveloped parts of our blocks or concession areas. For the year ended December 31, 2018, the Llanos 34 Block contained 67% of our net proved reserves and generated 76% of our production, the Fell In order to protect our exploration and production rights in our license areas, Block contained 6% of our net proved reserves and generated 8% of our total we must meet various drilling and declaration requirements. In general, unless production, the BCAM-40 Concession contained 3% of our net proved reserves we make and declare discoveries within certain time periods specified in our and generated 8% of our production, the Aguada Baguales Block contained various special operation contracts (Contratos Especiales de Operación para 3% of our proved reserves and generated 3% of our total production and the la Exploración y Explotación de Yacimientos de Hidrocarburo; hereinafter Morona Block contained 17% of our net proved reserves. While our continuing “CEOP”), E&P Contracts and concession agreements, our interests in the expansion with new exploratory blocks incorporated in our portfolio mean undeveloped parts of our license areas may lapse. Should the prospects we that the above mentioned blocks may be expected to be a less significant have identified under these contracts and agreements yield discoveries, component of our overall business, we cannot be sure that we will be able we may face delays in drilling these prospects or be required to relinquish to continue diversifying our reserves and production. Resulting from these, these prospects. The costs to maintain or operate the CEOPs, E&P Contracts any government intervention, impairment or disruption of our production and concession agreements over such areas may fluctuate and may increase due to factors outside of our control or any other material adverse event in significantly, and we may not be able to meet our commitments under such our operations in such blocks would have a material adverse effect on our contracts and agreements on commercially reasonable terms or at all, which business, financial condition and results of operations. may force us to forfeit our interests in such areas. For example, in 2016, after fulfilling the committed exploratory commitments, five exploratory blocks Our contracts in obtaining rights to explore and develop oil and natural were relinquished to the ANP. See “Item 4. Information on the Company—B. gas reserves are subject to contractual expiration dates and operating Business Overview—Our operations—Operations in Brazil.” conditions, and our CEOPs, E&P Contracts and concession agreements are subject to early termination in certain circumstances. In Peru, the rights to explore and produce hydrocarbons are granted through a license contract signed with Perupetro. The scope and schedule of such Under certain CEOPs, E&P Contracts and concession agreements to which development will depend on us and Petroperu. The license contract could we are or may in the future become parties, we are or may become subject be terminated by Perupetro if the development obligations included in to guarantees to perform our commitments and/or to make payment for such agreement are not fulfilled. In addition, there is also an exploratory other obligations, and we may not be able to obtain financing for all such commitment consisting of the drilling of one exploratory well every two and obligations as they arise. If such obligations are not complied with when a half years. Failure to fulfill the exploratory commitment will lead to acreage due, in addition to any other remedies that may be available to other parties, relinquishment materially affecting the project. Moreover, we have entered this could result in cancelation of our CEOPs, E&P Contracts and concession into a Joint Investment Agreement with Petroperu by which, subject to the agreements or dilution or forfeiture of interests held by us. As of December economic and technical feasibility of the Morona Project, we are obliged 31, 2018, the aggregate outstanding amount of this potential liability for to bear 100% of capital cost required to carry out long test to existing well guarantees was US$38.9 million, mainly related to capital commitments in Situche Central 3X, and if we decide to continue with the project after Isla Norte, Campanario and Flamenco Blocks in Chile, rounds 11, 12 and 13 that, to the existing well Situche Central 2X. In addition, we are required to concessions in Brazil, the Morona Block in Peru and the VIM-3, and Llanos 34 cover any capital or operational expenditures associated with the project Blocks in Colombia. See “Item 4. Information on the Company—B. Business until December 31, 2020. We expect these expenditures to be substantially Overview—Our operations” and Note 32.2 to our Consolidated Financial reimbursed by Petroperu from revenues associated with future sales. Failure Statements. 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 Additionally, certain of the CEOPs, E&P Contracts and concession agreements claims from Petroperu. 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 For additional details regarding the status of our operations with respect beyond their original expiration dates, there is no assurance that we can do to our various special contracts and concession agreements, see “Item 4. so on terms that are acceptable to us or at all, although some CEOPs contain Information on the Company—B. Business Overview—Our operations.” provisions enabling exploration extensions. GeoPark 51 In Colombia, our E&P Contracts may be subject to early termination for a compensation to which we are entitled may not be sufficient to compensate breach by the parties, a default declaration, application of any of the contracts’ us for the full value of our assets. Moreover, in the event of early termination of unilateral termination clauses or pursuant to termination clauses mandated any concession agreement due to failure to fulfill obligations thereunder, we by Colombian law. Anticipated termination declared by the ANH results in the may be subject to fines and/or other penalties. 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 Peru, License Contracts for hydrocarbon exploitation are in force and will in contracts with the Colombian government during a certain period of time. remain in effect for 30 years. This term is non-renewable. With regard to the See “Item 4. Information on the Company—B. Business Overview—Significant Morona Block, approximately one-third of the contract term has already Agreements—Colombia—E&P Contracts.” elapsed, and twenty years remain. Nevertheless, since May 14, 2013, the License Contract related to the Morona Block is under force majeure. During a In Chile, our CEOPs provide for early termination by Chile in certain force majeure period contract terms are suspended (including the term time) circumstances, depending upon the phase of the CEOP. For example, pursuant as long as the party to the contract is fulfilling certain obligations related to to the Fell Block CEOP, Chile has the right to terminate the CEOP under certain obtaining environmental permits, as is currently the case with the Morona circumstances if we fail to perform. If the Fell Block CEOP is terminated in Block. The term of the agreement will be extended by the same amount of the exploitation phase, we will have to transfer to Chile, free of charge, any time it has been suspended by a force majeure event. The concession year productive wells and related facilities, provided that such transfer does not expiration is related to the approval of the environmental impact assessment interfere with our abandonment obligations and excluding certain pipelines for the project’s development. The expiration of the License Contract will occur and other assets. See “Item 4. Information on the Company—B. Business twenty years after the approval of the environmental impact assessment. The Overview—Significant Agreements—Chile—CEOPs—Fell Block CEOP.” If the License Contract is also subject to early termination in case of our breach of CEOP is terminated early due to a breach of our obligations, we may not be contractual obligations. In such an event, all the existing facilities and wells entitled to compensation. Our CEOPs for the Tierra del Fuego Blocks, which located in the block will be transferred, without charge, to Perupetro, and we are in the exploration phase, may be subject to early termination during this will have to carry out abandonment plans for remediation and restoration of phase under certain circumstances, including if we fail to perform under any polluted area in the block and for de-commission the facilities that are no the terms of the CEOPs, voluntarily relinquish all areas under the CEOPs or longer required for the block’s operations. 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 In Argentina, hydrocarbon exploration permits and exploitation concessions are released from all obligations under the CEOPs, except for obligations are subject to termination for: (a) failure to pay any annual license fees within regarding the abandonment of fields, if any. See “Item 4. Information on the three months after they are due; (b) failure to pay royalties within three Company—B. Business Overview—Significant Agreements—Chile—CEOPs.” months after they are due; (c) material and unjustified failure to comply with There can be no assurance that the early termination of any of our CEOPs the specified obligations in respect to productivity, conservation, investments, would not have a material adverse effect on us. In addition, according to works or special benefits; (d) repeated infringement of the obligations to the Chilean Constitution, Chile is entitled to expropriate our rights in our submit demandable information, to facilitate inspections by the competent CEOPs for reasons of public interest. Although Chile would be required to authority or to employ the proper techniques for the execution of the indemnify us for such expropriation, there can be no assurance that any such works; (e) failure to request an exploitation concession after a commercial indemnification will be paid in a timely manner or in an amount sufficient to discovery or to submit a development program after obtaining an exploitation cover the harm to our business caused by such expropriation. concession; (f ) the bankruptcy of the holder declared by a court; (g) the death or liquidation of the holder; or, (h) failure to comply with the obligation to In Brazil, concession agreements in the production phase generally may be transport hydrocarbons for third parties under open access conditions or renewed at the ANP’s discretion for an additional period, provided that a repeated infringement of the tariff regime approved for such transport. Before renewal request is made at least 12 months prior to the termination of the declaring the termination under any of the grounds provided under items (a), concession agreement and there has not been a breach of the terms of the (b), (c), (d), (e), and (h), notice shall be served, requiring the holder to remedy concession agreement. We expect that all our concession agreements will any such infringement. Upon expiration, relinquishment or termination of any provide for early termination in the event of: (i) government expropriation permit or concession, the holder of such permit or concession shall surrender for reasons of public interest; (ii) revocation of the concession pursuant to the to the government the acreage together with all of the improvements, terms of the concession agreement; or (iii) failure by us or our partners to fulfill facilities, wells and other equipment that may have been used in the all of our respective obligations under the concession agreement (subject to a performance of the activities. cure period). Administrative or monetary sanctions may also be applicable, as determined by the ANP, which shall be imposed based on applicable law and Early termination or nonrenewal of any CEOP, E&P Contract or concession regulations. In the event of early termination of a concession agreement, the agreement could have a material adverse effect on our business, financial situation or results of operations. 52 GeoPark 20F We sell almost all of our natural gas in Chile to a single customer, who has in costs, or the rate of production of any non-operated and, to an extent, any the past temporarily idled its principal facility. non-wholly-owned, assets. For the year ended December 31, 2018, almost all of our natural gas sales As of December 31, 2018, we are not the operator of 27% or sole owner of in Chile were made to Methanex under a long-term contract, the Methanex 31% of the blocks included in our portfolio. See “Item 4. Information on the Gas Supply Agreement, which expires on December 31, 2026. Under the Company—B. Business Overview—Operations in Colombia, Operations in agreement, Methanex committed to purchase up to 400,000 SCM/d of gas Chile, Operations in Brazil, Operations in Peru and Operations in Argentina.” produced by us. Due to the decline in our gas production, the commitment was reduced to 315,000 SCM/d in 2018, according to the initial terms of In addition, the terms of the joint operation agreements or association our contract. The commitment has remained at 315,000 SCM/d for 2019. agreements governing our other partners’ interests in almost all of the blocks We also hold an option to deliver up to 15% above this volume. Sales to that are not wholly-owned or operated by us require that certain actions be Methanex represented 3% of our consolidated revenues for the year ended approved by supermajority vote. The terms of our other current or future December 31, 2018. Methanex also buys gas from ENAP and a consortium license or venture agreements may require at least the majority of working that Methanex has formed with ENAP. If Methanex were to decrease or cease interests to approve certain actions. As a result, we may have limited ability to its purchase of gas from us, this would have a material adverse effect on our exercise influence over operations or prospects in the blocks operated by our revenues derived from the sale of gas. 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 Methanex has two methanol producing facilities at its Cabo Negro could eventually affect our rights in exploration and production contracts production facility, near the city of Punta Arenas in southern Chile. Methanex in some of our blocks in Colombia, Argentina and Brazil. Our dependence has relied on local suppliers of natural gas, including ENAP, for its operations. on our partners could prevent us from realizing our target returns for those We alone cannot supply Methanex with all the natural gas it requires for its discoveries or prospects. operations. In 2018, Argentina approved export permits of natural gas to Chile, including deliveries to Methanex. 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 In the past, the Methanex plant was idled due to an anticipated insufficient activities or the amount of capital expenditures and may therefore not be able supply of natural gas. The supply of natural gas decreased during the winter to carry out our key business strategies of minimizing the cycle time between months of 2015 due to the increase in seasonal gas demand from the city discovery and initial production at such properties. The success and timing of of Punta Arenas, to which gas producers, including us, gave priority by exploration and development activities operated by our partners will depend delivering gas to the city through Methanex which re-sold our gas to ENAP. on a number of factors that will be largely outside of our control, including: In May 2017, the Methanex plant shut down because of a technical failure • the timing and amount of capital expenditures; which affected our natural gas production and sales for 20 days. See “Item • the operator’s expertise and financial resources; 4. Information on the Company—B. Business Overview—Marketing and • approval of other block partners in drilling wells; delivery commitments—Chile.” • the scheduling, pre-design, planning, design and approvals of activities and However, we cannot be sure that Methanex will continue to purchase the • selection of technology; and gas from us, including the above committed levels, or that its efforts to • the rate of production of reserves, if any. reduce the risk of future shut-downs will be successful, which could have a processes; material adverse effect on our gas revenues. Additionally, we cannot be sure This limited ability to exercise control over the operations on some of our that Methanex will have sufficient supplies of gas to operate its plant and license areas may cause a material adverse effect on our financial condition continue to purchase our gas production or that methanol prices would be and results of operations. 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 Acquisitions that we have completed and any future acquisitions, could have a material adverse effect on our business, financial condition and strategic investments, partnerships or alliances could be difficult to results of operations. integrate and/or identify, could divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely We are not, and may not be in the future, the sole owner or operator of all affect our financial results, including impairment of goodwill and other of our licensed areas and do not, and may not in the future, hold all of the intangible assets. working interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated One of our principal business strategies includes acquisitions of properties, GeoPark 53 prospects, reserves and leaseholds and other strategic transactions, including our competitiveness and growth opportunities. Moreover, if we fail to properly in jurisdictions in which we do not currently operate. The successful evaluate acquisitions, alliances or investments, we may not achieve the acquisition and integration of producing properties requires an assessment of anticipated benefits of any such transaction, and we may incur costs in excess several factors, including: • recoverable reserves; • future oil and natural gas prices; • development and operating costs; and 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 • potential environmental and other liabilities. securities, existing cash, cash equivalents or investments, or a combination of the foregoing. Acquisitions financed with the issuance of our equity The accuracy of these assessments is inherently uncertain. In connection securities could be dilutive, which could affect the market price of our stock. with these assessments, we perform a review of the subject properties Acquisitions financed with debt could require us to dedicate a substantial that we believe to be generally consistent with industry practices. Our portion of our cash flow to principal and interest payments and could subject review and the review of advisors and independent reserves engineers us to restrictive covenants. 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 The PN-T-597 Concession Agreement in Brazil may not close. their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental conditions are not In Brazil, GeoPark Brasil is a party to a class action filed by the Federal necessarily observable even when an inspection is undertaken. We, advisors Prosecutor’s Office regarding a concession agreement of exploratory Block or independent reserves engineers may apply different assumptions when PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and assessing the same field. Even when problems are identified, the seller gas bidding round held in November 2013. The Brazilian Federal Court issued may be unwilling or unable to provide effective contractual protection an injunction against the ANP and GeoPark Brasil in December 2013 that against all or part of the problems. We often are not entitled to contractual prohibited GeoPark Brasil’s execution of the concession agreement until the indemnification for environmental liabilities and acquire properties on ANP conducted studies on whether drilling for unconventional resources would an “as is” basis. Even in those circumstances in which we have contractual contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark indemnification rights for pre-closing liabilities, it remains possible that Brasil, at the instruction of the ANP, signed the concession agreement, which the seller will not be able to fulfill its contractual obligations. There can be included a clause prohibiting GeoPark Brasil from conducting unconventional no assurance that problems related to the assets or management of the exploration activity in the area. Despite the clause containing the prohibition, companies and operations we have acquired, or operations we may acquire the judge in the case concluded that the concession agreement should not or add to our portfolio in the future, will not arise in future, and these be executed. Thus, GeoPark Brasil requested that the ANP comply with the problems could have a material adverse effect on our business, financial decision and annul the concession agreement, which the ANP’s Board did on condition and results of operations. 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. Significant acquisitions and other strategic transactions may involve other risks, including: There is no assurance that we will be able to enter into a concession agreement • diversion of our management’s attention to evaluating, negotiating and in the PN-T-597 Block that would be favorable to our exploration goals. See integrating significant acquisitions and strategic transactions; “Item 8—Financial Information—A. Consolidated statements and other • challenge and cost of integrating acquired operations, information financial information—Legal proceedings.” management and other technology systems and business cultures with ours while carrying on our ongoing business; The present value of future net revenues from our proved reserves will not • contingencies and liabilities that could not be or were not identified during necessarily be the same as the current market value of our estimated oil the due diligence process, including with respect to possible deficiencies in and natural gas reserves. the internal controls of the acquired operations; and • challenge of attracting and retaining personnel associated with acquired You should not assume that the present value of future net revenues from operations. our proved reserves is the current market value of our estimated oil and natural gas reserves. For the year ended December 31, 2018, we have based It is also possible that we may not identify suitable acquisition targets or the estimated discounted future net revenues from our proved reserves on strategic investment, partnership or alliance candidates. Our inability to the 12-month unweighted arithmetic average of the first-day-of-the-month identify suitable acquisition targets, strategic investments, partners or price for the preceding 12 months. Actual future net revenues from our oil and alliances, or our inability to complete such transactions, may negatively affect natural gas properties will be affected by factors such as: 54 GeoPark 20F • actual prices we receive for oil and natural gas; Furthermore, some of our customers may be highly leveraged, and, in any • actual cost of development and production expenditures; event, are subject to their own operating expenses. Therefore, the risk we • the amount and timing of actual production; and face in doing business with these customers may increase. Other customers • changes in governmental regulations, taxation or the taxation invariability may also be subject to regulatory changes, which could increase the risk of provisions in our CEOPs. defaulting on their obligations to us. Financial problems experienced by our The timing of both our production and our incurrence of expenses in customers could result in the impairment of our assets, a decrease in our connection with the development and production of oil and natural gas operating cash flows and may also reduce or curtail our customers’ future properties will affect the timing and amount of actual future net revenues from use of our products and services, which may have an adverse effect on our proved reserves, and thus their actual value. In addition, the 10% discount revenues and may lead to a reduction in reserves. 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 We may not have the capital to develop our unconventional oil and gas time and risks associated with us or the oil and natural gas industry in general. resources. The development of our proved undeveloped reserves may take longer We have identified opportunities for analyzing the potential of and may require higher levels of capital expenditures than we currently unconventional oil and gas resources in some of our blocks and concessions. anticipate. Therefore, our proved undeveloped reserves ultimately may not Our ability to develop this potential depends on a number of factors, be developed or produced. including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access As of December 31, 2018, 38% of our net proved reserves are developed. to and availability of equipment, services and personnel and drilling results. Development of our undeveloped reserves may take longer and require In addition, as we have no previous experience in drilling and exploiting higher levels of capital expenditures than we currently anticipate. Additionally, unconventional oil and gas resources, the drilling and exploitation of such delays in the development of our reserves or increases in costs to drill and unconventional oil and gas resources depends on our ability to acquire develop such reserves will reduce the standardized measure value of our the necessary technology, to hire personnel and other support needed estimated proved undeveloped reserves and future net revenues estimated for extraction or to obtain financing and venture partners to develop such for such reserves, and may result in some projects becoming uneconomic, activities. Because of these uncertainties, we cannot give any assurance causing the quantities associated with these uneconomic projects to no as to the timing of these activities, or that they will ultimately result in the longer be classified as reserves. This was due to the uneconomic status of the realization of proved reserves or meet our expectations for success. 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 Our operations are subject to operating hazards, including extreme weather no assurance that we will not experience similar delays or increases in costs events, which could expose us to potentially significant losses. to drill and develop our reserves in the future, which could result in further reclassifications of our reserves. Our operations are subject to potential operating hazards, extreme weather conditions and risks inherent to drilling activities, seismic registration, We are exposed to the credit risks of our customers and any material exploration, production, development and transportation and storage of crude nonpayment or nonperformance by our key customers could adversely oil, such as explosions, fires, car and truck accidents, floods, labor disputes, affect our cash flow and results of operations. social unrest, community protests or blockades, guerilla attacks, security Our customers may experience financial problems that could have a our or third-party facilities. Any of these events could have a material adverse significant negative effect on their creditworthiness. Severe financial problems effect on our exploration and production operations or disrupt transportation encountered by our customers could limit our ability to collect amounts or other process-related services provided by our third-party contractors. breaches, pipeline ruptures and spills and mechanical failure of equipment at owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. We are highly dependent on certain members of our management and technical team, including our geologists and geophysicists, and on our The combination of declining cash flows as a result of declines in commodity ability to hire and retain new qualified personnel. 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 The ability, expertise, judgment and discretion of our management and our significant reduction of our customers’ liquidity and limit their ability to make technical and engineering teams are key in discovering and developing oil and payments or perform on their obligations to us. natural gas resources. Our performance and success are dependent to a large extent upon key members of our management and exploration team, and their GeoPark 55 loss or departure would be detrimental to our future success. In addition, our We have contracted with and intend to continue to hire third parties to ability to manage our anticipated growth depends on our ability to recruit and perform services related to our operations. We could be held liable for some retain qualified personnel. Our ability to retain our employees is influenced by or all environmental, health and safety costs and liabilities arising out of the economic environment and the remote locations of our exploration blocks, our actions and omissions as well as those of our block partners, third-party which may enhance competition for human resources where we conduct our contractors, predecessors or other operators. To the extent we do not address activities, thereby increasing our turnover rate. There is strong competition these costs and liabilities or if we do not otherwise satisfy our obligations, our in our industry to hire employees in operational, technical and other areas, operations could be suspended, terminated or otherwise adversely affected. and the supply of qualified employees is limited in the regions where we There is a risk that we may contract with third parties with unsatisfactory operate and throughout Latin America generally. The loss of any of our key environmental, health and safety records or that our contractors may be management or other key employees of our technical team or our inability to unwilling or unable to cover any losses associated with their acts and hire and retain new qualified personnel could have a material adverse effect omissions. on us. We and our operations are subject to numerous environmental, health and certain environmental laws and regulations applicable to us in the countries safety laws and regulations which may result in material liabilities and in which we operate, we could be held responsible for all of the costs relating Releases of regulated substances may occur and can be significant. Under costs. 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 We and our operations are subject to various international, foreign, federal, waste disposal, emissions and other operational practices might require us to state and local environmental, health and safety laws and regulations remediate contamination, or retrofit facilities, at substantial cost. We also could governing, among other things, the emission and discharge of pollutants into be held liable for any and all consequences arising out of human exposure to the ground, air or water; the generation, storage, handling, use, transportation such substances or for other damage resulting from the release of hazardous and disposal of regulated materials; and human health and safety. Our substances to the environment, property or to natural resources, or affecting operations are also subject to certain environmental risks that are inherent endangered species or sensitive environmental areas. We are currently required in the oil and gas industry and which may arise unexpectedly and result to, and in the future may need to, plug and abandon sites in certain blocks in in material adverse effects on our business, financial condition and results each of the countries in which we operate, which could result in substantial of operations. Breach of environmental laws could result in environmental costs. administrative investigations and/or lead to the termination of our concessions and contracts. Other potential consequences include fines and/or criminal or In addition, we expect continued and increasing attention to climate change civil environmental actions. For instance, non-governmental organizations issues. Various countries and regions have agreed to regulate emissions of seeking to preserve the environment may bring actions against us or other oil greenhouse gases including methane (a primary component of natural gas) and gas companies in order to, among other things, halt our activities in any and carbon dioxide (a byproduct of oil and natural gas combustion). The of the countries in which we operate or require us to pay fines. Additionally, regulation of greenhouse gases and the physical impacts of climate change in Colombia, recent rulings have provided that environmental licenses are in the areas in which we, our customers and the end-users of our products administrative acts subject to class actions that could eventually result in their operate could adversely impact our operations and the demand for our cancellation, with potential adverse impacts on our E&P Contracts. products. We have not been and may not be at all times in complete compliance with In Peru, the beginning of the construction and development phase of environmental permits that we are required to obtain for our operations and the Morona Block is subject to the approval of an environmental impact the environmental and health and safety laws and regulations to which we assessment by the Peruvian environmental authority. If such environmental are subject. If we fail to comply with such requirements, we could be fined impact assessment is not approved during the first half of 2019, we will not be or otherwise sanctioned by regulators, including through the revocation of able to transport all the goods and materials required for the development of our permits or the suspension or termination of our operations. If we fail to the project during the fluvial transportation window of the Morona River in obtain, maintain or renew permits in a timely manner or at all, our operations 2019 and the construction stage of the project will be negatively impacted. If could be adversely affected, impeded, or terminated, which could have a this is the case, the beginning of the production stage of the Morona Project material adverse effect on our business, financial condition or results of could also be impacted. operations. Some environmental licenses related to operation of the Manati Field production system and natural gas pipeline have expired. However, the Environmental, health and safety laws and regulations are complex and change operator submitted in a timely manner a request for renewal of those licenses frequently, and our costs of complying with such laws and regulations may and as such this operation is not in default as long as the regulator does not adversely affect our results of operations and financial condition. See “Item state its final position on the renewal. 56 GeoPark 20F 4. Information on the Company—B. Business Overview—Health, safety and cash flow to fund acquisitions, working capital, capital expenditures and other environmental matters” and “Item 4. Information on the Company—B. Business general corporate purposes; Overview—Industry and regulatory framework.” • place us at a competitive disadvantage compared to certain of our competitors that have less debt; Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could • • limit our ability to borrow additional funds; in the case of our secured indebtedness, lose assets securing such increase the future costs of doing business, cause delays or impede our indebtedness upon the exercise of security interests in connection with a plans, and materially adversely affect our operations. default; Hydraulic fracturing of unconventional oil and gas resources is a process and that involves injecting water, sand, and small volumes of chemicals into • limit our flexibility in planning for, or reacting to, changes in our operations the wellbore to fracture the hydrocarbon-bearing rock thousands of feet or business and the industry in which we operate. • make us more vulnerable to downturns in our business or the economy; below the surface to facilitate a higher flow of hydrocarbons into the wellbore. We are contemplating such use of hydraulic fracturing in the The indenture governing our Notes due 2024 includes covenants production of oil and natural gas from certain reservoirs, especially shale restricting dividend payments. For a description, see “Item 5. Operating formations. We currently are not aware of any proposals in Colombia, and Financial Review and Prospects—B. Liquidity and Capital Resources— Chile, Brazil, Argentina or Peru to regulate hydraulic fracturing beyond the Indebtedness—Notes due 2024.” regulations already in place. However, various initiatives in other countries with substantial shale gas resources have been or may be proposed As a result of these restrictive covenants, we are limited in the manner or implemented to, among other things, regulate hydraulic fracturing in which we conduct our business, and we may be unable to engage in practices, limit water withdrawals and water use, require disclosure of favorable business activities or finance future operations or capital needs. fracturing fluid constituents, restrict which additives may be used, or We have in the past been unable to meet incurrence tests under the implement temporary or permanent bans on hydraulic fracturing. If any indenture governing our prior notes, which limited our ability to incur of the countries in which we operate adopts similar laws or regulations, indebtedness. Failure to comply with the restrictive covenants included in which is something we cannot predict right now, such adoption our Notes due 2024 would not trigger an event of default. could significantly increase the cost of, impede or cause delays in the implementation of any plans to use hydraulic fracturing for unconventional Similar restrictions could apply to us and our subsidiaries when we oil and gas resources. refinance or enter into new debt agreements which could intensify the risks Our indebtedness and other commercial obligations could adversely affect described above. our financial health and our ability to raise additional capital and prevent Our business could be negatively impacted by security threats, including us from fulfilling our obligations under our existing agreements and cybersecurity threats as well as other disasters, and related disruptions. borrowing of additional funds. As of December 31, 2018, we had US$447 million of total indebtedness including deliberate attacks or unintentional events, have also increased in outstanding on a consolidated basis, consisting primarily of our US$425.0 the world. Computer and telecommunications systems are used to conduct million Notes due 2024, which we issued in September 2017. As of December our exploration, development and production activities and have become 31, 2018, our annual debt service obligation was US$27.7 million, see “Item an integral part of our business. Our business processes depend on the 5. Operating and Financial Review and Prospects—B. Liquidity and Capital availability, capacity, reliability and security of our information technology As dependence on digital technologies has increased, cyber incidents, Resources—Indebtedness.” Our indebtedness could: 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 • limit our capacity to satisfy our obligations with respect to our implemented internal control procedures to assure the security of our data, indebtedness, and any failure to comply with the obligations of any of our we cannot guarantee that these measures will be sufficient for this purpose. debt instruments, including restrictive covenants and borrowing conditions, Cyber-attacks could compromise our computers and telecommunications could result in an event of default under the agreements governing our systems and result in disruptions to our business operation necessary to indebtedness; deliver our production to market or the loss of our data. • require us to dedicate a substantial portion of our cash flow from operations to the payments on our indebtedness, thereby reducing the availability of our Although we have extended our security policy to the main systems of GeoPark 57 the Company and implemented strategies to mitigate the impact from problem that may damage our information technology infrastructure. cybersecurity threats, reinforcing the defenses in case of denial of service and increasing the monitoring of suspicious activities, our technologies, systems, Certain cyber incidents, such as surveillance, may remain undetected for networks, and those of our business partners have been and may continue to an extended period. A cyber incident involving our information systems be the target of cyber-attacks or information security breaches, which could and related infrastructure, or that of our business partners, could disrupt lead to disruptions in critical systems, unauthorized release of confidential or our business plans and negatively impact our operations. Although to date protected information, corruption of data or other disruptions of our business we have not experienced any significant cyber-attacks, there can be no operations. The ability of the information technology function to support our assurance that we will not be the target of cyber-attacks in the future or suffer business in the event of a security breach or a disaster such as fire or flood such losses related to any cyber-incident. As cyber threats continue to evolve, and our ability to recover key systems and information from unexpected we may be required to expend significant additional resources to continue to interruptions cannot be fully tested and there is a risk that, if such an event modify or enhance our protective measures or to investigate and remediate actually occurs, we may not be able to address immediately the repercussions any information security vulnerabilities. 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 Risks relating to the countries in which we operate business or perform some business processes in a timely manner. We have implemented strategies to mitigate the impact from these types of events. Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may In addition, the oil and gas industry has become increasingly dependent operate in the future. on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, All of our current operations are located in South America. If local, regional software programs are used to interpret seismic data, manage drilling rigs, or worldwide economic trends adversely affect the economy of any of the conduct reservoir modeling and reserves estimation, and to process and countries in which we have investments or operations, our financial condition record financial and operating data. We depend on digital technology, and results from operations could be adversely affected. including information systems and related infrastructure as well as cloud application and services, to process and record financial and operating data, Oil and natural gas exploration, development and production activities are communicate with our employees and business partners, analyze seismic and subject to political and economic uncertainties (including but not limited to drilling information, estimate quantities of oil and gas reserves and for many changes in energy policies or the personnel administering them), changes other activities related to our business. Our business partners, including in laws and policies governing operations of foreign-based companies, vendors, service providers, co-venturers, purchasers of our production, expropriation of property, cancellation or modification of contract rights, and financial institutions, are also dependent on digital technology. As revocation of consents or approvals, the obtaining of various approvals from dependence on digital technologies has increased, cyber incidents, including regulators, foreign exchange restrictions, price controls, currency fluctuations, deliberate attacks or unintentional events, have also increased. royalty increases and other risks arising out of foreign governmental A cyber-attack could include gaining unauthorized access to digital systems community-based actions, such as protests or blockades, guerilla activities, for purposes of misappropriating assets or sensitive information, corrupting terrorism, acts of sabotage, territorial disputes and insurrection. In addition, data, or causing operational disruption, or result in denial-of-service on we are subject both to uncertainties in the application of the tax laws in the websites. Our technologies, systems, networks, and those of our business countries in which we operate and to possible changes in such tax laws (or partners may become the target of cyber-attacks or information security the application thereof ), each of which could result in an increase in our tax breaches that could result in the unauthorized release, gathering, monitoring, liabilities. These risks are higher in developing countries, such as those in sovereignty, as well as to risks of loss due to civil strife, acts of war and misuse, loss or destruction of proprietary and other information, or other which we conduct our activities. disruption of our business operations. Our employees have been and will continue to be targeted by parties using fraudulent “spam” and “phishing” The main economic risks we face and may face in the future because of our emails to misappropriate information or to introduce viruses or other operations in the countries in which we operate include the following: malware through “trojan horse” programs to our computers. These emails • difficulties incorporating movements in international prices of crude oil and appear to be legitimate emails sent by us but direct recipients to fake exchange rates into domestic prices; websites operated by the sender of the email or request that the recipient • the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s send a password or other confidential information through email or or Brazil’s relations with multilateral credit institutions, such as the IMF, will download malware. Despite our efforts to mitigate “spoof” and “phishing” impact negatively on capital controls, and result in a deterioration of the emails through education, “spoof” and “phishing” activities remain a serious business climate; 58 GeoPark 20F • inflation, exchange rate movements (including devaluations), exchange can be no assurance that we will be able to maintain our projected cash flow control policies (including restrictions on remittance of dividends), price and profitability following any increase in taxes applicable to us and to our instability and fluctuations in interest rates; • liquidity of domestic capital and lending markets; • tax policies; and operations. The political and economic uncertainty in Brazil along with the ongoing “Lava • the possibility that we may become subject to restrictions on repatriation of Jato” investigations regarding corruption at Petrobras may hinder the growth earnings from the countries in which we operate in the future. of the Brazilian economy and could have an adverse effect on our business. In addition, our operations in these areas increase our exposure to risks of Our Brazilian operations represent 5% of our revenues as of December 31, guerilla activities, social unrest, local economic conditions, political disruption, 2018. The Brazilian economy has been experiencing a slowdown. Inflation, civil disturbance, community protests or blockades, expropriation, piracy, tribal unemployment and interest rates have increased more recently and the conflicts and governmental policies that may: disrupt our operations; require Brazilian reais has weakened significantly in comparison to the US$. Our us to incur greater costs for security; restrict the movement of funds or limit results of operations and financial condition may be adversely affected by the repatriation of profits; lead to U.S. government or international sanctions; limit economic conditions in Brazil. 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 Petrobras and certain other Brazilian companies in the energy and geographic areas where we operate have experienced, and may experience infrastructure sectors are facing investigations by the Securities Commission in the future, political instability, and losses caused by these disruptions may of Brazil (Comissão de Valores Mobiliários), the U.S. Securities and Exchange not be covered by insurance. Consequently, our exploration, development and Commission (the “SEC”), the Brazilian Federal Police and the Brazilian Federal production activities may be substantially affected by factors which could have Prosecutor’s Office in connection with corruption allegations (the “Lava a material adverse effect on our results of operations and financial condition. We Jato” investigations). Depending on the duration and outcome of such cannot guarantee that current programs and policies that apply to the oil and investigations, the companies involved may face downgrades from rating gas industry will remain in effect. agencies, funding restrictions and a reduction in their revenues. Given the significance of the companies under investigation including Petrobras, this Our operations may also be adversely affected by laws and policies of the could adversely affect Brazil’s growth prospects and could have a protracted jurisdictions, including Bermuda, Colombia, Chile, Brazil, Argentina, Peru, Spain, effect on the oil and gas industry. In addition to the recent economic crisis, the United Kingdom, the Netherlands and other jurisdictions in which we do protests, strikes and corruption scandals have led to a fall in confidence. 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 We depend on maintaining good relations with the respective host jurisdictions. For example, in 2018 the Colombian government introduced tax governments and national oil companies in each of our countries of operation. reforms with provisions that are effective January 1, 2019. See Note 16 to our Consolidated Financial Statements. With regards to Chile, although our CEOPs The success of our business and the effective operation of the fields in each of our have protection against tax changes through invariability tax clauses, potential countries of operation depend upon continued good relations and cooperation issues may arise on certain aspects not clearly defined in current or future tax with applicable governmental authorities and agencies, including national oil reforms. companies such as Ecopetrol, ENAP, Petrobras, Petroperu and YPF. For instance, for the year ended December 31, 2018, 100% of our crude oil and condensate Changes in any of these laws or policies or the implementation thereof, and sales in Chile were made to ENAP, the Chilean state-owned oil company. In uncertainty over potential changes in policy or regulations affecting any addition, our Brazilian operations in BCAM-40 Concession provide us with a long- of the factors mentioned above or other factors in the future may increase term off-take contract with Petrobras, the Brazilian state-owned company that the volatility of domestic securities markets and securities issued abroad by covers 100% of net proved gas reserves in the Manati Field, one of the largest companies operating in these countries, which could materially and adversely non-associated gas fields in Brazil. If we, the respective host governments and the affect our financial position, results of operations and cash flows. Furthermore, national oil companies are not able to cooperate with one another, it could have we may be subject to the exclusive jurisdiction of courts outside the United an adverse impact on our business, operations and prospects. 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 Oil and natural gas companies in Colombia, Chile, Brazil, Argentina and Peru such dispute. Changes in tax laws may result in increases in our tax payments, do not own any of the oil and natural gas reserves in such countries. which could materially adversely affect our profitability and increase the prices of our products and services, restrict our ability to do business in our Under Colombian, Chilean, Brazilian, Peruvian and Argentine law, all onshore and existing and target markets and cause our results of operations to suffer. There offshore hydrocarbon resources in these countries are owned by the respective GeoPark 59 sovereign. Although we are the operator of the majority of the blocks and For example, in Brazil there is potential liability for personal injury, property concessions in which we have a working and/or economic interest and generally damage and other types of damages. Failure to comply with these laws and have the power to make decisions as how to market the hydrocarbons we regulations also may result in the suspension or termination of operations produce, the Chilean, Colombian, Brazilian, Peruvian and Argentine governments or our being subjected to administrative, civil and criminal penalties, which have full authority to determine the rights, royalties or compensation to be paid could have a material adverse effect on our financial condition and expected by or to private investors for the exploration or production of any hydrocarbon results of operations. We expect to also operate in a consortium in some of reserves located in their respective countries. our concessions, which, under the Brazilian Petroleum Law, establishes joint and strict liability among consortium members, and failure to maintain the If these governments were to restrict or prevent concessionaires, including us, appropriate licenses may result in fines from the ANP, ranging from R$10 from exploiting oil and natural gas reserves, or otherwise interfered with our to R$500 million. In addition, there is a contractual requirement in Brazilian exploration through regulations with respect to restrictions on future exploration concession agreements regarding local content, which has become a and production, price controls, export controls, foreign exchange controls, significant issue for oil and natural gas companies operating in Brazil given income taxes, expropriation of property, environmental legislation or health the penalties related with breaches thereof. The local content requirement and safety, this could have a material adverse effect on our business, financial will also apply to the production sharing contract regime. See “Item 4. condition and results of operations. Information on the Company—B. Business Overview—Our operations— Additionally, we are dependent on receipt of government approvals or permits to Operations in Brazil.” develop the concessions we hold in some countries. There can be no assurance Significant expenditures may be required to ensure our compliance that future political conditions in the countries in which we operate will not result with governmental regulations related to, among other things, licenses in changes to policies with respect to foreign development and ownership of for drilling operations, environmental matters, drilling bonds, reports oil, environmental protection, health and safety or labor relations, which may concerning operations, the spacing of wells, unitization of oil and natural gas negatively affect our ability to undertake exploration and development activities accumulations, local content policy and taxation. 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 Colombia has experienced and continues to experience internal security issues countries may delay our operations or may affect the status of our contractual that have had or could have a negative effect on the Colombian economy. arrangements or our ability to meet contractual obligations. Oil and gas operators are subject to extensive regulation in the countries in of Colombia (FARC) signed a peace agreement, pursuant to which the In 2016, the Colombian government and the Revolutionary Armed Forces which we operate. FARC agreed to demobilize its troops and to hand over its weapons to a United Nations mission. Our business, financial condition and results of The Colombian, Chilean, Brazilian, Peruvian and Argentine hydrocarbons operations could be adversely affected by rapidly changing economic or industries are subject to extensive regulation and supervision by their social conditions, including the Colombian government’s response to current respective governments in matters such as the environment, social peace agreements and negotiations with other groups, including the ELN, responsibility, tort liability, health and safety, labor, the award of exploration which may result in legislation that increases our tax burden or that of other and production contracts, the imposition of specific drilling and exploration Colombian companies. obligations, taxation, foreign currency controls, price controls, export and import restrictions, capital expenditures and required divestments. In some ELN has targeted crude oil pipelines in Colombia, including the Caño Limón- countries in which we operate, such as Colombia, we are required to pay a Coveñas pipeline, and other related infrastructure, disrupting the activities of percentage of our expected production to the government as royalties. See certain oil and natural gas companies and resulting in unscheduled shut- “Item 4. Information on the Company—B. Business Overview—Industry and downs of transportation systems. These activities, their possible escalation regulatory framework—Colombia” and see Note 32.1 to our Consolidated and the effects associated with them have had and may have in the future a Financial Statements. In Argentina, energy regulation gives absolute negative impact on the Colombian economy or on our business, which may priority to domestic gas supply, which in case of a gas shortage occurs, will affect our employees or assets. restrict our ability to fulfill our export commitments, if any. This regulation also established subsidies to domestic gas prices, which may negatively In addition, from time to time, community protests and blockades may arise affect our revenues considering market prices. See “Item 4. Information near our operations in Colombia, which could adversely affect our business, on the Company—B. Business Overview—Industry and regulatory financial condition or results of operations. framework—Argentina.” 60 GeoPark 20F Risks related to our common shares An active, liquid and orderly trading market for our common shares may not investment is if the price of our stock appreciates. develop and the price of our stock may be volatile, which could limit your ability to sell our common shares. We have never paid, and do not expect to pay in the foreseeable future, cash dividends on our common shares. Any decision to pay dividends in the Our common shares began to trade on the New York Stock Exchange (the future, and the amount of any distributions, is at the discretion of our board “NYSE”) on February 7, 2014, and as a result have a limited trading history. of directors and our shareholders, and will depend on many factors, such as We cannot predict the extent to which investor interest in our company will our results of operations, financial condition, cash requirements, prospects maintain an active trading market on the NYSE, or how liquid that market and other factors. Due to losses resulting from the oil price decline in previous will be in the future. years, accumulated losses amount to US$206.7 million as of December 31, The market price of our common shares may be volatile and may be 2018. influenced by many factors, some of which are beyond our control, We are also subject to Bermuda legal constraints that may affect our ability including: to pay dividends on our common shares and make other payments. Under • our operating and financial performance and identified potential drilling the Companies Act, 1981 (as amended) of Bermuda (“Bermuda Companies locations, including reserve estimates; Act”), we may not declare or pay a dividend if there are reasonable grounds • quarterly variations in the rate of growth of our financial indicators, such as for believing that we are, or would after the payment be, unable to pay our net income per common share, net income and revenues; liabilities as they become due or that the realizable value of our assets would • changes in revenue or earnings estimates or publication of reports by thereafter be less than our liabilities. We are also subject to contractual equity research analysts; • fluctuations in the price of oil or gas; restrictions under certain of our indebtedness. • speculation in the press or investment community; We are a holding company and our only material assets are our equity • sales of our common shares by us or our shareholders, or the perception interests in our operating subsidiaries and our other investments; as a that such sales may occur; • involvement in litigation; • changes in personnel; • announcements by the company; result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us. • domestic and international economic, legal and regulatory factors As a holding company, our only material assets are our cash on hand, the unrelated to our performance. equity interests in our subsidiaries and other investments. Our principal • variations in our quarterly operating results; source of revenue and cash flow is distributions from our subsidiaries. Thus, • volatility in our industry, the industries of our customers and the global our ability to service our debt, finance acquisitions and pay dividends to our securities markets; • changes in our dividend policy; stockholders in the future is dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to make upstream cash • risks relating to our business and industry, including those discussed above; distributions to us. Our subsidiaries are and will be separate legal entities, • strategic actions by us or our competitors; and although they may be wholly-owned or controlled by us, they have • actual or expected changes in our growth rates or our competitors’ growth no obligation to make any funds available to us, whether in the form of rates; loans, dividends, distributions or otherwise. The ability of our subsidiaries • investor perception of us, the industry in which we operate, the investment to distribute cash to us will also be subject to, among other things, opportunity associated with our common shares and our future performance; restrictions that are contained in our subsidiaries’ financing and joint • adverse media reports about us or our directors and officers; venture agreements, availability of sufficient funds in such subsidiaries • addition or departure of our executive officers; and applicable state laws and regulatory restrictions. Claims of creditors • change in coverage of our company by securities analysts; of our subsidiaries generally will have priority as to the assets of such • trading volume of our common shares; subsidiaries over our claims and claims of our creditors and stockholders. • future issuances of our common shares or other securities; To the extent the ability of our subsidiaries to distribute dividends or other • terrorist acts; payments to us could be limited in any way, our ability to grow, pursue • the release or expiration of transfer restrictions on our outstanding business opportunities or make acquisitions that could be beneficial to our common shares. businesses, or otherwise fund and conduct our business could be materially We have never declared or paid, and do not expect to pay in the limited. foreseeable future, cash dividends on our common shares, and, We may not be able to fully control the operations and the assets of our consequently, your only opportunity to achieve a return on your joint ventures and we may not be able to make major decisions or take GeoPark 61 timely actions with respect to our joint ventures unless our joint venture concentration of ownership may have the effect of delaying, preventing partners agree. We may, in the future, enter into joint venture agreements or deterring a change of control of our company, could deprive our imposing additional restrictions on our ability to pay dividends. 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 Sales of substantial amounts of our common shares in the public market, or market price of our common shares. See “Item 7. Major Shareholders and the perception that these sales may occur, could cause the market price of Related Party Transactions—A. Major shareholders” for a more detailed our common shares to decline. description of our share ownership. We may issue additional common shares or convertible securities in the As a foreign private issuer, we are subject to different U.S. securities laws future, for example, to finance potential acquisitions of assets, which we and NYSE governance standards than domestic U.S. issuers. This may intend to continue to pursue. Sales of substantial amounts of our common afford less protection to holders of our common shares, and you may not shares in the public market, or the perception that these sales may occur, receive corporate and company information and disclosure that you are could cause the market price of our common shares to decline. This could accustomed to receiving or in a manner in which you are accustomed to also impair our ability to raise additional capital through the sale of our receiving it. equity securities. Under our memorandum of association, we are authorized to issue up to 5,171,949,000 common shares, of which 60,483,447 common As a foreign private issuer, the rules governing the information that we shares were outstanding as of December 31, 2018. We cannot predict the disclose differ from those governing U.S. corporations pursuant to the size of future issuances of our common shares or the effect, if any, that Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although future sales and issuances of shares would have on the market price of our we intend to report quarterly financial results and report certain material common shares. 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 Provisions of the Notes due 2024 could discourage an acquisition of us by of their occurrence and our quarterly or current reports may contain less a third party. 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 Certain provisions of the Notes due 2024 could make it more difficult or not be subject to review by the SEC. Our exemption from Section 16 rules more expensive for a third party to acquire us or may even prevent a third regarding sales of common shares by insiders means that you will have less party from acquiring us. For example, upon the occurrence of a fundamental data in this regard than shareholders of U.S. companies that are subject to change, holders of the Notes due 2024 will have the right, at their option, to the Exchange Act. As a result, you may not have all the data that you are require us to repurchase all of their notes at a purchase price equal to 101% of accustomed to having when making investment decisions. For example, our the principal amount thereof plus any accrued and unpaid interest (including officers, directors and principal shareholders are exempt from the reporting any additional amounts, if any) to the date of purchase. By discouraging an and “short-swing” profit recovery provisions of Section 16 of the Exchange acquisition of us by a third party, these provisions could have the effect of Act and the rules thereunder with respect to their purchases and sales of our depriving the holders of our common shares of an opportunity to sell their common shares. The periodic disclosure required of foreign private issuers common shares at a premium over prevailing market prices. 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 Certain shareholders have substantial control over us and could limit your published by or about U.S. public companies. See “Item 10. Additional ability to influence the outcome of key transactions, including a change of Information—H. Documents on display.” control. As a foreign private issuer, we are exempt from complying with certain Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief corporate governance requirements of the NYSE applicable to a U.S. issuer, Executive Officer, Mr. Jamie Coulter, director, Mr. Constantine Papadimitriou, including the requirement that a majority of our board of directors consist of director, and Mr. Juan Cristóbal Pavez, director, control 35.4% of our independent directors as well as the requirement that shareholders approve outstanding common shares as of March 15, 2019, holding the shares either any equity issuance by us which represents 20% or more of our outstanding directly or through privately held funds. As a result, these shareholders, if common shares. As the corporate governance standards applicable to us acting together, would be able to influence or control matters requiring are different than those applicable to domestic U.S. issuers, you may not approval by our shareholders, including the election of directors and the have the same protections afforded under U.S. law and the NYSE rules as approval of amalgamations, mergers or other extraordinary transactions. shareholders of companies that do not have such exemptions. 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 There are regulatory limitations on the ownership and transfer of our 62 GeoPark 20F common shares which could result in the delay or denial of any transfers you law, the purpose of which is the enforcement of a sanction, power or right might seek to make. 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. The Bermuda Monetary Authority (the “BMA”), must specifically approve all jurisdictions, including certain remedies under U.S. federal securities laws, issuances and transfers of securities of a Bermuda exempted company like us would not be available under Bermuda law or enforceable in a Bermuda unless it has granted a general permission. We are able to rely on a general court, as they would be contrary to Bermuda public policy. 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 The transfer of our common shares may be subject to capital gains taxes and/or other appointed stock exchange, to and among persons who are pursuant to indirect transfer rules in Chile. 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 In September 2012, Chile established “indirect transfer rules,” which impose delayed. taxes, under certain circumstances, on capital gains resulting from indirect transfers of shares, equity rights, interests or other rights in the equity, We are a Bermuda company, and it may be difficult for you to enforce control or profits of a Chilean entity, as well as on transfers of other assets judgments against us or against our directors and executive officers. and property of permanent establishments or other businesses in Chile (“Chilean Assets”). As we indirectly own Chilean Assets, the indirect transfer We are incorporated as an exempted company under the laws of Bermuda rules would apply to transfers of our common shares provided certain and substantially all of our assets are located in Colombia, Chile, Argentina, conditions outside of our control are met. If such conditions were present and Brazil and Peru. In addition, most of our directors and executive officers as a result the indirect transfer rules were to apply to sales of our common reside outside the United States and all or a substantial portion of the shares, such sales would be subject to indirect transfer tax on the capital assets of such persons are located outside the United States. As a result, gain realized in connection with such sales. For a description of the indirect it may be difficult or impossible to effect service of process within the transfer rules and the conditions of their application see “Item 10. Additional United States upon us, or to recover against us on judgments of U.S. courts, Information—E. Taxation—Chilean tax on transfers of shares.” including judgments predicated upon the civil liability provisions of the U.S. federal securities laws. Further, no claim may be brought in Bermuda As an exempted company incorporated under Bermuda law, our operations against us or our directors and officers in the first instance for violation may be subject to economic substance requirements. 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. On December 5, 2017, following an assessment of the tax policies of various However, a Bermuda court may impose civil liability, including the countries by the Code of Conduct Group for Business Taxation of the European possibility of monetary damages, on us or our directors and officers if the Union (the “COCG”), the Council of the EU approved and published Council facts alleged in a complaint constitute or give rise to a cause of action conclusions containing a list of non-cooperative jurisdictions for tax purposes under Bermuda law. (the “Conclusions”). Although not considered so-called “non-cooperative jurisdictions,” certain countries, including Bermuda, were listed as having There is no treaty in force between the United States and Bermuda “tax regimes that facilitate offshore structures which attract profits without providing for the reciprocal recognition and enforcement of judgments in real economic activity.” In connection with the Conclusions, and to avoid civil and commercial matters. As a result, whether a United States judgment being placed on the list of “non-cooperative jurisdictions,” the government of would be enforceable in Bermuda against us or our directors and officers Bermuda, among others, committed to addressing COCG proposals relating to depends on whether the U.S. court that entered the judgment is recognized economic substance for entities doing business in or through their respective by the Bermuda court as having jurisdiction over us or our directors and jurisdictions and to pass legislation to implement any appropriate changes by officers, as determined by reference to Bermuda conflict of law rules. A the end of 2018. 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 The Economic Substance Act 2018 and the Economic Substance Regulations judgment debtor had submitted to the jurisdiction of the U.S. court, and 2018 of Bermuda (the “Economic Substance Act” and the “Economic Substance the issue of submission and jurisdiction is a matter of Bermuda (not U.S.) Regulations”, respectively) became operative on December 31, 2018. The law. Economic Substance Act applies to every registered entity in Bermuda that engages in a relevant activity and requires that every such entity shall In addition, and irrespective of jurisdictional issues, the Bermuda courts maintain a substantial economic presence in Bermuda. Relevant activities for will not enforce a U.S. federal securities law that is either penal or contrary the purposes of the Economic Substance Act are banking business, insurance to Bermuda public policy. An action brought pursuant to a public or penal business, fund management business, financing business, leasing business, GeoPark 63 Information on the company headquarters business, shipping business, distribution and service center from the list and sanctions or other financial, tax or regulatory measures business, intellectual property holding business and conducting business as a were applied by European Member States to countries on the list or further holding entity, which may include a pure equity holding entity. economic substance requirements were imposed by Bermuda, our business The Bermuda Economic Substance Act provides that a registered entity that carries on a relevant activity complies with economic substance requirements ITEM 4. INFORMATION ON THE COMPANY if (a) it is directed and managed in Bermuda, (b) its core income-generating activities (as may be prescribed) are undertaken in Bermuda with respect to A. History and development of the company the relevant activity, (c) it maintains adequate physical presence in Bermuda, (d) it has adequate full time employees in Bermuda with suitable qualifications General could be negatively impacted. and (e) it incurs adequate operating expenditure in Bermuda in relation to the We were incorporated as an exempted company pursuant to the laws of relevant activity. Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, A registered entity that carries on a relevant activity is obliged under the our shareholders approved a change in our name to GeoPark Limited, Bermuda Economic Substance Act to file a declaration in the prescribed form effective from July 31, 2013. We maintain a registered office in Bermuda at (the “Declaration”) with the Registrar of Companies (the “Registrar”) on an Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. annual basis. Our principal executive offices are located at Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, Street The Economic Substance Regulations provide that minimum economic 94 N° 11-30, 8, 9, 8th floor, Bogotá, Colombia, telephone number +57 1 743 substance requirements shall apply in relation to an entity if the entity is a 2337, and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number pure equity holding entity which only holds or manages equity participations, +5411 4312 9400. and earns passive income from dividends, distributions, capital gains and other incidental income only. The minimum economic substance The SEC maintains an internet website that contains reports, proxy, requirements include a) compliance with applicable corporate governance information statements and other information about issuers, like us, that requirements set forth in the Bermuda Companies Act 1981 including file electronically with the SEC. The address of that website is www.sec.gov. keeping records of account, books and papers and financial statements and b) The Company’s website address is www.geo-park.com. The information submission of an annual economic substance declaration form. Additionally, contained on, or that can be accessed through, the Company’s website is not the Economic Substance Regulations provide that a pure equity holding entity part of, and is not incorporated into, this Annual Report. complies with economic substance requirements where it also has adequate employees for holding and managing equity participations, and adequate Our Company premises in Bermuda. We are a leading independent oil and natural gas exploration and production (“E&P”) company with operations in Latin America and a proven track record If we fail to comply with our obligations under the Bermuda Economic of growth in production and reserves since 2006. We operate in Colombia, Substance Act or any similar law applicable to us in any other jurisdictions, Chile, Brazil, Argentina and Peru. We are focused on Latin America because we could be subject to financial penalties and spontaneous disclosure of we believe it is one of the most important regions globally in terms of information to foreign tax officials in related jurisdictions and may be struck hydrocarbon potential, with less presence of independent E&P companies from the register of companies in Bermuda or such other jurisdiction. Any of compared to the United Stated and Canada. In this region, much of the these actions could have a material adverse effect on our business, financial acreage has historically been controlled or owned by state-owned companies. condition and results of operations. We believe that these factors create an opportunity for smaller, more agile companies like us to build a long-term business. On March 12, 2019, Bermuda was placed by the EU on its list of non- cooperative jurisdictions for tax purposes due to an issue with Bermuda’s We produced a net average of 36.0 mboepd during the year ended December economic substance legislation which was not resolved in time for the 31, 2018, of which 79%, 8%, 5% and 8% were, respectively, in Colombia, Chile, EU’s deadline. At present, the impact of being included on the list of non- Argentina and Brazil, and of which 85% was oil. As of August 31, 2018, we cooperative jurisdictions for tax purposes is unclear. While Bermuda has were ranked as the third largest oil operator in Colombia, where we made now amended its legislation which the Bermuda Government has stated the largest new oil field discovery in the last 20 years. We are the first private has addressed this issue and expects to be removed from the list of non- oil and gas operator in Chile and we are operating the inaugural project of cooperative jurisdictions at the EU’s Economic and Financial Affairs Council’s Petroperu in its return to the upstream business in Peru. We partnered with next meeting which is scheduled to be in May 2019, there can be no assurance Petrobras in one of Brazil’s largest producing gas fields and we have recently that Bermuda will be removed from such list. If Bermuda is not removed increased our activities in Argentina with the acquisition of three blocks in the Neuquén Basin in March 2018. 64 GeoPark 20F We have built our company around three principal capabilities: each of the Otway and Tranquilo Blocks. Then, in 2011, ENAP awarded us the • as an Explorer, which is our ability, experience, methodology and creativity opportunity to obtain operating working interests in each of the Isla Norte, to find and develop oil and gas reserves in the subsurface, based on the best Flamenco and Campanario Blocks in Tierra del Fuego, Chile, which we refer science, solid economics and ability to take the necessary managed risks. to collectively as the Tierra del Fuego Blocks, and in 2012, jointly with ENAP, • as an Operator, which is our ability to execute in a timely manner and to we entered into CEOPs with Chile for the exploration and exploitation of have the know-how to profitably drill for, produce, treat, transport and sell hydrocarbons within these blocks. our oil and gas – with the drive and persistence to find solutions, overcome obstacles, seize opportunities and achieve results. Also, in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14% • as a Consolidator, which is our ability and initiative to assemble the right equity interest in GeoPark TdF for US$148.0 million. balance and portfolio of upstream assets in the right hydrocarbon basins in the right regions with the right partners and at the right price – coupled with Finally, in November 2018, we acquired all of LGI’s equity interest in the visions and skills to transform and improve value above ground. GeoPark’s Chilean and Colombian subsidiaries. This acquisition increased GeoPark’s equity interest to 100% in its Colombian and Chilean businesses. We believe that our risk and capital management policies have enabled The acquisition price includes a fixed payment of US$81 million already paid us to compile a geographically diverse portfolio of properties that at closing, plus two equal installments of US$15 million each, to be paid in balances exploration, development and production of oil and gas. These June 2019 and June 2020. Additionally, three contingent payments of US$5 attributes have also allowed us to raise capital and to partner with premier million each could be payable over the next three years, subject to certain international companies. Most importantly, we believe we have developed a production thresholds being exceeded. distinctive culture within our organization that promotes and rewards trust, partnership, entrepreneurship and merit. Consistent with this approach, Colombia all of our employees are eligible to participate in our long-term incentive In the first quarter of 2012, we moved into Colombia by acquiring three program, which is the Performance-Based Employee Long-Term Incentive privately held E&P companies: (i) Winchester Oil and Gas S.A., a Colombian Program. See “Item 6. Directors, Senior Management and Employees—B. branch of a sociedad anónima incorporated under the laws of Panama, Compensation—Equity Incentive Compensation—Performance-Based which merged into GeoPark Colombia SAS (“Winchester”), (ii) La Luna Oil Employee Long-Term Incentive Program.” Company Limited S.A., a sociedad anónima incorporated under the laws of Our regional platform and risk-balanced portfolio has been built following Cuerva LLC, a limited liability company incorporated under the laws of the a proactive but conservative long term technical approach, converting state of Delaware, which merged into GeoPark Colombia SAS (“Cuerva”). projects into successful value-generating assets. These acquisitions provided us with an attractive platform of reserves and Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) Hupecol resources in Colombia. History We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park, In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia who have over 40 years of international oil and natural gas experience, Coöperatie U.A by making a US$14.9 million capital contribution and respectively. Mr. O’Shaughnessy currently serves as our Chairman and Mr. assuming the existing debt for an amount of US$4.9 million. Park currently serves as our Chief Executive Officer and Deputy Chairman. Brazil We are a leading independent oil and natural gas exploration and In May 2013, we entered into agreements to expand our operations to Brazil. production (“E&P”), company with operations in Latin America and a proven As of 2014, following the Rio das Contas acquisition, we have a 10% working track record of growth in production and reserves since 2006. We operate in interest in the BCAM-40 Concession, which includes an interest in the Manati Colombia, Chile, Brazil, Argentina and Peru. Field operated by Petrobras. Our History can be summarized by our growth in each country and our Since 2013, we have participated in the Brazilian ANP Bid Rounds and have performance in the capital markets: been awarded exploratory concessions in each one of them. Chile Argentina In 2006, after demonstrating our technical expertise and committing to an In August 2014, in partnership with Pluspetrol, a private oil and gas exploration and development plan, we obtained a 100% operating working company with strong presence across Latin America, we were awarded two interest in the Fell Block from the Republic of Chile. In 2008 and 2009, we exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of continued our growth in Chile by acquiring operating working interests in the 2014 Mendoza Bidding Round in Argentina. GeoPark 65 In July 2015, we signed a farm-in agreement with Wintershall for the CN-V In September 2017, we issued US$425.0 million aggregate principal amount Block in the Mendoza Province. of 6.50% senior notes due 2024. The net proceeds from the Notes were used by us (i) to make a capital contribution to our wholly-owned subsidiary, Additionally, in December 2017, we agreed to purchase from Pluspetrol, a GeoPark Latin America Limited Agencia en Chile, providing it with sufficient 100% working interest and operatorship of the Aguada Baguales, El Porvenir funds to fully repay the Notes due 2020 and to pay any related fees and and Puesto Touquet blocks in Argentina. We entered into an asset purchase expenses, including a call premium, and (ii) for general corporate purposes, agreement with Pluspetrol, dated December 18, 2017 (the “APA”). The including capital expenditures, such as the acquisition of Aguada Baguales, transaction closed on March 27, 2018. El Porvenir and Puesto Touquet blocks in the Neuquén Basin in Argentina, to repay existing indebtedness, including the Itaú loan. Finally, In June 2018, we entered into a partnership with YPF, the state- owned oil company of Argentina, on the Los Parlamentos block – a large B. Business Overview high potential block in the Neuquén Basin with both conventional and unconventional prospects. Peru We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. Since our inception, we have supported our growth through our prospect In October 2014, we expanded our footprint into Peru by acquiring the development efforts, drilling program, long-term strategic partnerships and Morona Block in a joint venture with Petroperu. This transaction awarded us alliances with key industry participants, accessing debt and equity capital a 75% working interest of the Morona Block. In December 2016, we obtained markets, developing and retaining a technical team with vast experience final regulatory approval for our acquisition of the Morona Block in Peru. The and creating a successful track record of finding and producing oil and gas Joint Investment and Operating Agreement dated October 1, 2014 and its in Latin America. A key factor behind our success ratio is our experienced amendments were closed on December 1, 2016, following the issuance of team of geologists, geophysicists and engineers, including professionals with Supreme Decree 031-2016-MEM. specialized expertise in the geology of Colombia, Chile, Brazil, Argentina and New potential country platform Peru. In December 2015, as part of our long-term effort to build an upstream The following map shows the countries in which we have blocks with working platform in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo and/or economic interests as of December 31, 2018. For information on our Alfa for onshore projects, however, no blocks were awarded to us. working interests in each of these blocks, see “—Our assets” below. In March 2019, we announced our expected entry into Ecuador through the acquisition of the Espejo and Perico exploratory blocks in the Intracampos Bid Round in the Oriente Basin located in the north-eastern part of Ecuador. The blocks were awarded to the GeoPark and Frontera consortium (50% GeoPark, 50% Frontera) in the form of production sharing contracts. The final award is contingent upon regulatory approvals and the execution of the contracts is expected for the second quarter of 2019. See “Item 3. Key Information—A. Risk Factors—Risks relating to our business— Our pending acquisition of the Espejo and Perico blocks in Ecuador is subject to regulatory approvals.” Funding In February 2013, we issued US$300 million aggregate principal amount of 7.50% senior secured notes due 2020 (the “Notes due 2020”). We repurchased US$284 million aggregate principal amount of the outstanding Notes due 2020 in September 2017 and redeemed the remaining US$16 million aggregate principal amount outstanding in October 2017. In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over- allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares. 66 GeoPark 20F Brazil Blocks POT-T-619 REC-T-94 BCAM-40 Manati SEAL-T-268 POT-T-747 POT-T-785 REC-T-128 PN-T-597(2) Argentina Blocks Sierra del Nevado Puelen CN-V Aguada Baguales El Porvenir Puesto Touquet Los Parlamentos(3) COLOMBIA Colombia Blocks La Cuerva(1) Llanos 34 Yamu(1) Llanos 32 Abanico VIM-3 Peru Blocks Morona PERU BRAZIL PA CIFIC OCEAN ARGENTINA ATLANTIC OCEAN Chile Blocks Fell Isla Norte Campanario Flamenco Tranquilo CHILE (1) On November 2, 2018, GeoPark and Perenco Oil and Gas executed a purchase and sale agreement in which Perenco agreed to purchase GeoPark’s 100% working interest in the La Cuerva and Yamu blocks. Closing of the transaction is subject to customary regulatory approvals. We will continue operating the blocks until the completion of the divestiture process. See “— Our operations—Operations in Colombia.” (2) The PN-T-597 is still subject to the entry into the concession agreement and absence of legal impediments, by the ANP in the Parnaíba Basin. See “—Our operations—Operations in Brazil.” (3) Subject to regulatory approvals. See “—Our operations—Operations in Argentina.” GeoPark 67 The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2018. For the year ended December 31 2018 Country Colombia Chile Brazil Peru Argentina Total Oil (mmbbl) Gas (bcf ) (mmboe) Oil equivalent 74.8 3.3 0.1 18.5 3.4 100.1 2.1 20.8 17.3 - 9.4 49.6 75.1 6.8 3.0 18.5 5.0 108.4 Revenues (in thousands of US$) 497,870 37,359 30,053 - 35,879 601,161 %Oil 100% 49% 3% 100% 68% 92% % of total revenues 83% 6% 5% -% 6% 100% (Our commitment to growth has translated into a strong compounded annual growth rate (“CAGR”), of 16% for production in the period from 2014 to 2018, as measured by boepd in the table below. For the year ended December 31, Average net production (mboepd) % oil The following table sets forth our production of oil and natural gas in the blocks in which we have a working and/or economic interest as of December 31, 2018. Average daily production For the year ended December 31, 2018 Oil production Total crude oil production (bopd) Natural gas production Total natural gas production (mcf/day) Oil and natural gas production 2018 36.0 85% 2017 27.6 83% 2016 22.4 75% 2015 20.4 74% 2014 19.7 74% Colombia Chile Brazil Argentina(1) Total 28,421 782 42 1,202 30,447 740 11,640 17,300 3,796 33,476 Total oil and natural gas production (mboepd) 28,545 2,722 2,925 1,835 36,027 (1) We acquired the Neuquén Blocks in March 2018. Production figures do not include production prior to their acquisition by us. Our assets We have a well-balanced portfolio of assets that includes working and/or economic interests in 25 hydrocarbon blocks, 24 of which are onshore blocks, including 10 in production as of December 31, 2018. Our assets give us access to more than 5 million gross exploratory and productive acres. According to the D&M Reserves Report, as of December 31, 2018, the blocks in Colombia, Chile, Brazil, Argentina and Peru in which we have a working interest had 108.4 mmboe of net proved reserves, with 69%, 6%, 3%, 5% and 17% of such net proved reserves located in Colombia, Chile, Brazil, Argentina and Peru, respectively. 68 GeoPark 20F We produced a net average of 36.0 mboepd during the year ended December Situche Central proven oil field, which we believe offers extensive exploration 31, 2018 of which 79%, 8%, 5% and 8%, were in Colombia, Chile, Argentina potential with several potential high impact prospects and plays. See “—Our and Brazil, respectively, and of which 85% was oil. operations—Operations in Peru.” We are the operator of the majority of the blocks in which we have a working Significant drilling inventory and resource potential from existing asset interest. Our strengths base Our portfolio includes large land holdings in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different geological We believe that we benefit from the following competitive strengths: formations, which provide several attractive opportunities with varying levels of risk. Our drilling inventory and our development plans target locations that High quality and diversified asset base built through a successful track provide attractive economics and support a predictable production profile, as record of organic growth and acquisitions demonstrated by our expansions in Colombia. Our assets include a diverse portfolio of oil and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys in Our geoscience team continues to identify new potential accumulations and Latin America. Throughout our history, we have delivered continuous growth in expand our inventory of prospects and drilling opportunities. our production, and our management team has been able to identify under- exploited assets and turn them into valuable, productive assets, and to allocate Continue to grow a risk-balanced asset portfolio resources effectively based on prevailing conditions. We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential • Colombia. In 2012, we acquired assets in Colombia at attractive prices, which opportunities, and on increasing production and reserves through finding, gave us access to exploratory and productive acres with many prospects. developing and producing oil and gas reserves in the countries in which we In the Llanos Basin, we pioneered a new play type combining structural operate. In general, when we enter a new country we look for a mix of three and stratigraphic traps. As a result, in the Llanos 34 Block our average daily elements: (i) producing fields, or existing discoveries with near-term possibility production has grown from 0 at the time of acquisition to more than 30,400 of production, to generate cash flows; (ii) an inventory of adjacent low-risk bopd as of December 31, 2018. prospects that can offer medium-term upside for steady growth; and (iii) a • Chile. In 2002, we acquired a non-operating working interest in the Fell Block periphery of higher-risk projects which have a potential to generate significant in Chile, which at the time had no material oil and gas production or reserves upside in the long run. despite having been actively explored and drilled over the course of more than 50 years. Since 2006, when we became the operator of the Fell Block For example, in Colombia, we acquired three companies simultaneously to we performed active exploration and development drilling that resulted in pursue a risk-balanced approach: one company had mainly proven production multiple oil and gas discoveries. and reserves to provide us with a steady cash flow base, and the remaining • Brazil. Since 2013, we have participated in the Brazilian ANP Bid Rounds and had highly prospective exploration license blocks. Within four years of entering were awarded exploratory concessions in each one of them. In 2014, we Colombia, we made multiple oil discoveries in block Llanos 34 that allowed us to acquired Rio das Contas, which gave us a 10% working interest in the BCAM- increase production and cash flows. 40 Concession, including the shallow-depth offshore Manati and Camarão Norte Fields in the Camamu-Almada Basin in the State of Bahia, which has We believe this approach will allow us to sustain continuous and profitable consistently self-funded its operations. The Manati Field has provided up to growth and also participate in higher risk growth opportunities with upside 3.7% of total gas produced in Brazil. potential. See “—Our operations.” • Argentina. During 2014, GeoPark and Pluspetrol were awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks as part of Platform and Funding the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa We are focused on continued growth utilizing a disciplined capital structure Mendocina de Energía S.A. (“EMESA”). In 2015, we acquired a 50% working and a conservative financial philosophy. Due to the volatile nature of interest in the CN-V Block in Mendoza from Wintershall Energía S.A. On commodity prices, expenditure discipline and a focus on disciplined capital December 18, 2017, we executed an asset purchase agreement (the “APA”) structure are critical to our business. Our multi-country platform and asset with Pluspetrol to acquire a 100% working interest and operatorship of portfolio is managed through our capital allocation methodology, which also the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina. allows us to quickly adapt and grow. Under this methodology, each country, Closing of the transaction occurred on March 27, 2018. has a local team running the business who recommends and advocates for • Peru. In December 2016, we expanded our footprint into Peru by acquiring the the projects with which they want to move forward. The corporate team then Morona Block in a joint venture with Petroperu. The Morona Block contains the ranks all of the projects based on economic, technical and strategic criteria, GeoPark 69 for the purpose of comparing projects. This also creates opportunities for the principal payments that were due in 2015 (amounting to approximately improvements in the projects that can, in turn, improve their ranking. Finally, US$15 million), which were divided pro-rata during the remaining principal once the production and reserve growth targets are defined, the corporate installments, starting in March 2016 and (ii) to increase the variable interest team decides the amount of capital to be invested and allocates that capital rate equal to the 6-month LIBOR + 4.0%. The loan was fully repaid in to the highest value-adding projects. As an example, for the 2019 capital September 2017. allocation process, over 135 projects were presented with a final selection of 74 which comprise our 2019 work program, under the base capital program. In February 2014, we commenced trading on the NYSE and raised US$98 Additionally, given the inherent oil price volatility, we design our work million (before underwriting commissions and expenses), including the over- programs to be flexible, which means that they can be increased or decreased allotment option granted to and exercised by the underwriters, through the depending on the oil price scenario. issuance of 13,999,700 common shares. We have historically benefited from access to debt and equity capital markets Strong cash flow and cash flows from operations, as well as other funding sources, which have We benefit from a strong cash flow from operating activities. For the year provided us with funds to finance our organic growth and the pursuit of ended December 31, 2018, cash provided by operating activities was potential new opportunities. US$256.2 million. Our cash flow from operating activities plays a significant We generated US$256.2 million and US$142.2 million in cash from operations in the years ended December 31, 2018 and 2017, respectively, and had Maintain financial strength role in funding our capital expenditures. US$127.7 million and US$134.8 million of cash and cash equivalents as of We seek to maintain a prudent and sustainable capital structure and a strong December 31, 2018 and 2017, respectively. financial position to allow us to maximize the development of our assets and capitalize on business opportunities as they arise. We intend to remain As of December 31, 2018, we had US$447.0 million of total outstanding financially disciplined by limiting substantially all our debt incurrence to indebtedness and over 96% of our debt had a maturity of 2024. identified projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers in addition During October 2018, we entered into a loan agreement with Banco to the international capital markets. Santander for Brazilian Real 77.6 million (equivalent to US$ 20 million at the moment of the loan execution) to repay an existing US$-denominated Our cash flow generation is complemented by our financial hedging program. intercompany loan, which matures in October 2020. As a result of this Since October 2016, we have entered into derivative financial instruments to transaction, our Brazilian subsidiary has significantly reduced its exposure to manage our exposure to oil price risk. The purpose of our hedging strategy is foreign currency fluctuation. to establish minimum oil prices to secure a stable cash flow and the execution of our work program. For the period commencing January 2018 to December In September 2017, we issued US$425.0 million aggregate principal amount 2018, we hedged between 13,000 and 14,000 bopd via zero premium collars of 6.50% senior notes due 2024 (the “Notes due 2024”). The Notes due 2024 and three-way hedges (US$10/bbl wide put spread and call), with a minimum contain incurrence-based limitations on the amount of indebtedness we can average Brent price of US$55 per barrel and a maximum average price of incur, see “Item 5. Operating and Financial Review and Prospects—Liquidity US$73 per barrel, representing 44% of our oil production for that period. For and capital resources—Indebtedness—Notes due 2024—Covenants.” the period from January 2019 to March 2019, we have secured 15,000 bopd with a minimum average price of US$64 per barrel and a maximum average In December 2015, we entered into an offtake and prepayment agreement price of US$92 per barrel via zero premium collars and three-way hedges with Trafigura under which we sold and delivered a portion of our Colombian (US$10/bbl wide put spread and call). For the period from April 2019 to June crude oil production to Trafigura. The offtake agreement also provided us 2019, we have secured 11,000 bopd with a minimum average price of US$65 with prepayment line of up to US$100 million, subject to applicable volumes per barrel and a maximum average price of US$91 per barrel via zero premium corresponding to the terms of the agreement, in the form of prepaid future oil collars and three-way hedges (US$10/bbl wide put spread and call). For the sales. period commencing July 2019 to September 2019, we have secured 5,000 bopd with a minimum average price of US$65 per barrel and a maximum In March 2014, we borrowed US$70.5 million pursuant to a five-year term average price of US$92 per barrel via zero premium collars. variable interest secured loan, secured by the benefits we receive under the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to In December 2018 we decided to manage our future exposure to local 6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das currency fluctuation with respect to income tax balances in Colombia. Contas acquisition. In March 2015, we reached an agreement to: (i) extend Consequently, we entered into a derivative financial instrument with a local 70 GeoPark 20F bank in Colombia, for an amount equivalent to US$ 92.1 million, in order to us with additional funding flexibility to pursue further acquisitions anticipate any currency fluctuation with respect to income taxes to be paid We benefit from a number of strong partnerships and relationships. In during the first half of 2019. Chile, we believe we have strong long-term commercial relationships with Methanex and ENAP, and in Colombia, we believe we have developed a strong We believe that by maintaining a disciplined capital structure and a relationship with Ecopetrol, the Colombian state-owned oil and gas company. conservative financial philosophy, including limiting our debt incurrence to In Brazil, we believe we will continue to derive benefits from the long-term specified projects with repayment sources and our use of financial hedges, we relationship GeoPark Brazil has with Petrobras. are positioned to maintain sufficient liquidity and remain flexible in volatile commodity price environments. Our financial flexibility also gives us the ability In February 2018, we announced the formation of a new long-term strategic to pursue new opportunities through future potential acquisitions. partnership to jointly acquire, invest in, and create value from upstream oil and gas projects with the objective of building a large-scale, economically- Pursue strategic acquisitions in Latin America profitable and risk-balanced portfolio of assets and operations across Latin We have historically benefited from, and intend to continue to grow through, America with ONGC Videsh, the wholly-owned subsidiary and international strategic acquisitions in Latin America. These acquisitions have provided us arm of Oil and Natural Gas Corporation Limited, India’s national oil company. with additional attractive platforms in the region. Our Colombian acquisitions, for example, highlight our ability to identify and execute on attractive growth Maintain our commitment to environmental, safety and social responsibility opportunities, as we have grown to become the third largest operator in A major component of our business strategy is our focus on and commitment Colombia. We acquired our interest in the Llanos 34 Block in the first quarter to our environmental and social responsibilities, in line with international of 2012 for US$30 million and have achieved 1P reserve PV-10 of US$1,340 standards. We see this as a fundamental element of ensuring long-term million as of December 31, 2018. Our enhanced regional portfolio, including business initiatives. We are committed to minimizing the impact of investment-grade countries and strong partnerships, position us as a regional our projects on the environment and aim to create mutually beneficial consolidator. We intend to continue to grow through strategic acquisitions in relationships with the local communities in which we operate in order other countries in Latin America, which we may consider from time to time. to enhance our ability to create sustainable value in our projects. These commitments are embodied in our in-house designed Environmental, Health, Our acquisition strategy is aimed at maintaining a balanced portfolio of lower- Safety and Security management program, which we refer to as “S.P.E.E.D.” risk cash flow-generating properties and assets that have upside potential, (Safety, Prosperity, Employees, Environment and Community Development). keeping a balanced mix of oil and gas-producing assets (though we expect Our S.P.E.E.D. program was developed in accordance with several international to remain weighted towards oil) and focusing on both assets and corporate quality standards, including ISO 14001 (for environmental management targets. issues), OHSAS 18001 (for occupational health and safety management issues), ISO 26000 (for social accountability and workers’ rights issues), and applicable Maintain a high degree of operatorship to control production costs World Bank standards. See “—Health, safety and environmental matters.” As of the date of this annual report, we are and intend to continue to be the operator of a majority of the blocks and concessions in which we have During 2016, we began the ISO 14001 certifying process through programs working interests. Operating the majority of our blocks and concessions gives related to the efficient use of natural resources and compliance with us the flexibility to allocate our capital and resources opportunistically and environmental regulation. We have also provided training to our staff and the efficiently within a diversified asset portfolio. We believe that this strategy has communities in which we operate with respect to these matters. allowed, and will continue to allow us, to leverage our unique culture, focused on excellence, and our talented technical, operating and management teams. In August 2017, we obtained the ISO 14001:2015 certification for our For example, as commodity prices were projected to decline throughout 2015, environmental management process for the design, construction, operation, we announced in the first quarter of 2015 a decision to shift our development maintenance, modernization and dismantlement of GeoPark Colombia plan primarily to our operations in the Llanos 34 Block to focus on the Llanos S.A.S.’s facilities, and the performance of exploration and oil and gas Basin, which had demonstrated strong returns on capital. Our operating team production activities in the Llanos 34 and VIM-3 blocks with a commitment to reacted quickly to pivot our operations that were unburdened by drilling continuously improve our processes. obligations and worked with our service partners to coordinate a smooth and efficient transition to a new plan. Since then we were able to control Highly committed founding shareholders and technical and management production costs, as exemplified by our average operating costs for the Llanos teams with proven industry expertise and technically-driven culture 34 Block, which were US$4.0 per boe for the year ended December 31, 2018. Our founding shareholders, management and operating teams have significant experience in the oil and gas industry and a proven technical and Long-term strategic partnerships and strong strategic relationships provide commercial performance record in onshore fields, as well as complex projects GeoPark 71 in Latin America and around the world, including expertise in identifying application of state-of-the-art technologies, agile processes and creative new acquisition and expansion opportunities. Moreover, we differentiate solutions to challenges in both our fields and our offices. Our guiding principle is ourselves from other E&P companies through our technically-driven culture, that everyone can innovate, and this is promoted through a cross-collaborative which fosters innovation, creativity and timely execution. Our geoscientists, and trust-based work environment. To ensure that this is taken as a key priority, geophysicists and engineers are pivotal to the success of our business as of 2018 we have included innovation as one of our metrics in our Balanced strategy, and we have created an environment and supplied the resources that Scorecard and have allocated seed money in our annual budget to kick-start enable our technical team to focus its knowledge, skills and experience on new projects. As an example of the success we have had, in 2018 we were finding and developing oil and gas fields. awarded a prize for innovative road safety measures by the Colombian Council In addition, we strive to provide a safe and motivating workplace for technology-based projects, such as cryobox virtual gas technology in Neuquén employees in order to attract, protect, retain and train a quality team in the Province, in Argentina, to put into production a well that was previously shut-in competitive marketplace for capable energy professionals. due to a lack of facilities, and a gas based artificial lift system for mature wells in of Security. Additionally, we have successfully implemented multiple new Our CEO, Mr. James F. Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, 2019 Strategy and Outlook Chile that results in low maintenance costs. drilling and production operations, surface and pipeline construction, legal Oil prices have been volatile since the end of 2014. In preparation for and regulatory issues, crude oil marketing and transportation and capital continued volatility, we have developed multiple scenarios for our 2019 capital raising for the industry. As of March 15, 2019, Mr. Park held 13.2% of our expenditure program. outstanding common shares. Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the oil price assumption of US$70 per barrel and calls for approximately US$220- and gas business internationally and in North America since 1976. As of March 240 million to fund our exploration and development, which we intend to 15, 2019, Mr. O’Shaughnessy held 11.5% of our outstanding common shares. fund through cash flows from operations and cash-in-hand, to be allocated Our preliminary base capital program for 2019 considers a reference oil approximately as follows: Our management and operating team has an average experience in the • Colombia: US$85-95 million. Continue to develop and appraise the Tigana energy industry of more than 25 years in companies such as Chevron, ENAP, and Jacana oil fields and target new exploration prospects in the Llanos basin. Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our • Chile: US$17-20 million. Develop and explore oil and gas targets, both history, our management and operating team has had success in unlocking conventional and unconventional, in the Fell and Tierra del Fuego blocks. unexploited value from previously underdeveloped assets. • Brazil: US$3-4 million. Focus on exploration drilling in onshore blocks. In addition, as of March 15, 2019, our executive directors and key management gas targets in the Neuquén Basin. (excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy and Mr. • Peru: US$95-105 million. Focus on construction of early production facilities James F. Park) owned 30.7% of our outstanding common shares, aligning their in the Morona block with the goal of putting the Situche Central light oil field interests with those of our shareholders and helping retain the talent we need into production by 2020, subject to approval of the environmental impact • Argentina: US$20-25 million. Focus on development and exploration oil and to continue to support our business strategy. See “Item 6. Directors, Senior assessment. Management and Employees—B. Compensation.” Our founding shareholders are also involved in our daily operations and strategy. In addition, we have developed downside and upside work program scenarios based on different oil prices and project performance. The downside scenario Technically-driven culture and capitalization of local knowledge work program considers a reference oil price assumption below US$65 We intend to continue to pursue strategies that maximize value. For this per barrel and consists of an alternative capital expenditure program of purpose, we intend to continue expanding our technical teams and to foster approximately US$120 million-US$140 million consisting mainly of certain a culture that rewards talent according to results. For example, we have been low risk and quick cash flow generating projects. The upside scenario work able to maintain the technical teams we inherited through our Colombian and program considers a reference oil price assumption above US$75 per barrel Brazilian acquisitions. We believe local technical and professional knowledge is or higher and consists of an alternative capital expenditure program of key to operational and long-term success and intend to continue to secure local approximately US$240 million-US$270 million to be selected from identified talent as we grow our business in different locations. projects designed to increase reserves and production. Innovation Our operations We are committed to an innovation culture driven by the continuous search and We have a well-balanced portfolio of assets that includes working and/or 72 GeoPark 20F economic interests in 25 hydrocarbon blocks, 24 of which are onshore blocks, • In November 2018 we signed an agreement with Perenco Oil and Gas to including 10 in production as of December 31, 2018, as well as in an additional divest the La Cuerva and Yamu blocks for $18 million plus a contingent payment shallow-offshore concession in Brazil that includes the Manati Field. In of $2 million, based on future oil prices; and addition, we have one concession in Brazil, the PN-T-597 Block, that is subject • In November 2018 we acquired LGI’s 20% equity interest in our Colombian to the entry into the concession agreement by the ANP and one concession in subsidiary, which expanded our participation in the valuable Llanos 34 block. Argentina, the Parlamentos Block, that remains subject to regulatory approval as of the date of this annual report. Operations in Colombia Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to an E&P Contract with the ANH, whereas “economic interests” are indirect Our Colombian assets currently give us access to more than 244,900 gross participation interests in the net revenues from a given block based on bilateral exploratory and productive acres across 6 blocks in what we believe to be one of agreements with the concessionaires. South America’s most attractive oil and gas geographies. The map below shows the location of the blocks in Colombia in which we have Since we entered Colombia in 2012, we have achieved consistent growth in working and/or economic interests. our oil production and proved reserves in Colombia, mainly achieved through successful exploration and development activities we made at our operated Llanos 34 Block, which as of December 31, 2018 accounts for 95% of our production and 97% of our proved reserves in Colombia. The table below shows average production and proved oil and gas reserves (derived from D&M Reserves Report) in Colombia for the years ended December 31, 2018, 2017 and 2016: Average net production (mboepd) Net proved reserves at year-end (mmboe) 2018 28.4 75.1 2017 21.8 65.5 2016 15.5 37.3 Highlights of the year ended December 31, 2018 related to our operations in Colombia included: • Successful drilling campaign with 21 gross wells drilled and put into production in the Jacana and Tigana oil fields in the Llanos 34 Block. This campaign includes the successful drilling and testing of Tigana Norte 9 appraisal well; • Discovery of the Chachalaca Sur oil field, following the successful drilling and testing of the Chachalaca Sur 1 exploration well, located on a fault trend to the west of the Tigana and Jacana oil fields; • Discovery of the new Tigui oil field, following the successful drilling and testing of the Tigui 1 exploration well; • Average net production increased by 30%, to 28.4 mboepd in 2018 from 21.8 mboepd in 2017; • Proved oil and gas reserves increased by 15% to 75.1 mmboe at year-end (1) On November 2, 2018, GeoPark and Perenco Oil and Gas executed a purchase and sale agreement in which Perenco agreed to purchase GeoPark’s 100% 2018, from 65.5 mmboe at year-end 2017 after producing 9.4 mmboe; working interest in the La Cuerva and Yamu blocks. Closing of the transaction • Capital expenditures increased by 21% to US$97.0 million in 2018 from is subject to customary regulatory approvals. We will continue operating the US$80.0 million in 2017; blocks until the completion of the divestiture process. See “—Our operations— • Maintenance of production and operating costs levels per barrel from US$5.6 Operations in Colombia.” in 2017 to US$5.5 in 2018; • Flowline construction to connect the Llanos 34 block oil fields to regional The table summarizes information about the blocks in Colombia in which we pipeline infrastructure is on budget and on schedule and expected to be have working interests as of and for the year ended December 31, 2018. operational in 2019; GeoPark 73 Block Llanos 34 La Cuerva Yamú Gross acres (thousand acres) Working interest(1) Partners(2) Operator Net proved reserves (mmboe)(3) Production (boepd) Basin Concession expiration year 82.2 45% Parex GeoPark 72.5 27,219 Llanos Exploration: 2019 Exploitation: 2039-2042(4) 24.5 100% 5.6 100% — — GeoPark GeoPark Llanos 32 57.0 12.5% Parex Parex VIM-3 48.9 100% — GeoPark 1.2 1.0 0.4 — 606 Llanos Exploitation: 2038 375 Llanos Production: 2036 306 Llanos Exploitation: 2039 — Magdalena Exploitation: 2045 Exploration: 2021 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in on it, and with 210 sq. km of existing 3D seismic data on which our team had mapped multiple exploration prospects. From 2012 to 2018 we engaged in such block. (2) Partners with working interests. (3) As of December 31, 2018. (4) The concession expiration year is set on a field by field basis. exploration and development activities that resulted in multiple new oil fields discovered and increased production and proved reserves year by year. Average net production in 2018 was 27,219 bopd and net reserves of 72.5 mmboe. The remaining commitment amounts to US$1.9 million at our working interest. The table summarizes information about the blocks in Colombia in which we Our partner in the Llanos 34 Block is Parex, which has a 55% interest. See “— have economic interests as of and for the year ended December 31, 2018 Our operations.” We operate in the block pursuant to an E&P Contract with the ANH. See “—Significant Agreements—Colombia—E&P Contracts—Llanos 34 Gross acres (thousand acres) 26.7 Economic interest(1) 10% Block Abanico Production Block E&P Contract.” Operator (boepd) Basin La Cuerva Block. We are the operator of, and have a 100% working interest Pacific 39 Magdalena in, the La Cuerva Block, which covers approximately 24,500 gross acres (99.1 (1) Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant to a joint operating agreement. sq. km). Average net oil production in 2018 was 606 bopd. We operate in the block pursuant to an E&P Contract with the ANH. On November 2, 2018 we executed a Sale Purchase Agreement with Perenco to sale the 100% working interest in the La Cuerva Block. Closing of the transaction is subject to Eastern Llanos Basin: (Llanos 34, La Cuerva, Yamú, Llanos 32, Abanico, and VIM-3 customary regulatory approvals, which are expected to occur during 2019. Blocks) The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region the Yamú Block, which covers approximately 5,588 gross acres (22.6 sq. km). of Colombia. Two giant fields (Caño Limón and Castilla), three major fields For the year ended December 31, 2018, our average net production was 375 (Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had bopd. On November 2, 2018 we executed a Sale Purchase Agreement with been discovered. The source rock for the basin is located beneath the east flank Perenco to sale the 100% working interest in the Yamú Block. Closing of the of the Eastern Cordillera, as a mixed marine-continental shale basinal facies transaction is subject to customary regulatory approvals, which are expected Yamú Block . We are the operator of, and have a 100% working interest in, of the Gachetá formation. The main reservoirs of the basin are represented to occur during 2019. by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous sequence, several sandstones are also considered to have good reservoirs. Llanos 32 Block . We have a 12.5% working interest in the Llanos 32 Block, as a result of our acquisition of an additional 2.5% interest on August 22, 2017. Llanos 34 Block . We are the operator of, and have a 45% working interest in, The Llanos 32 Block covers approximately 57,000 gross acres (230.7 sq. km). the Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq. Parex is the operator of this block and has a 87.5% working interest. Since km). We acquired an interest in and took operatorship of the block in the first 2015, the operator focused on the commissioning of a gas facility on this quarter of 2012, which at that time had no production, reserves or wells drilled block to produce natural gas and light crude oil from the Une formation and 74 GeoPark 20F to facilitate shipment of processed gas south to the adjacent Llanos 34 Block. Our Chilean blocks are located in the provinces of Ultima Esperanza, For the year ended December 31, 2018, our average net production in the Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil Llanos 32 Block was 306 bopd. The remaining commitment related to this and gas-producing area. As of December 31, 2018, the Magallanes Basin block is to drill one exploratory well before August 2018 was already fulfilled. accounted for all of Chile’s oil and gas production. Although this basin has On February 19, 2019 the parties to the Llanos 32 contract requested ANH been in production for over 60 years, we believe that it remains relatively to grant an extension of one year to phase 2 of the subsequent exploratory underdeveloped. program in order to drill an exploratory well amounting to US$ 4.7 million gross subject to ANH approval. We executed an agreement with Parex by Substantial technical data (seismic, geological, drilling and production which we obtained a 25% working interest in the remaining exploration areas information), developed by us and by ENAP, provides an informed base for of the block. new hydrocarbon exploration and development. Shut-in and abandoned fields may also have the potential to be put back in production by VIM-3 Block. On July 23, 2014 we were awarded an exploratory license during constructing new pipelines and plants. Our geophysical analyses suggest the 2014 Colombia Bidding Round, carried out by the ANH. We are entitled additional development potential in known fields and exploration potential to operate the block, in which we have a 100% working interest. The VIM-3 in undrilled prospects and plays, including opportunities in the Springhill, Block is located in the Lower Magdalena Basin. Our winning bid consisted of Tertiary, Tobífera and Estratos con Favrella formations. The Springhill committing to a Royalty X Factor of 3% and a minimum investment program formation has historically been the source of production in the Fell Block, of 200 sq. km of 2D seismic data acquisition and drilling one exploratory though the Estratos con Favrella shale formation is the principal source rock well, with a total estimated investment of US$22.3 million during the initial of the Magallanes Basin, and we believe it contains unconventional resource exploratory period ending February 2019. On June 21, 2017, the ANH potential. approved our relinquishment of 79.15% of the VIM 3 Block area. The remaining area covers 48,950 acres and the commitments described above are not Highlights of the year ended December 31, 2018 related to our operations in affected. On September 12, 2018, the ANH accepted our proposal to extend Chile included: the first exploratory phase for an additional period ending May 12, 2019. • Discovery of the Jauke gas field with successful drilling and testing of the Additionally, we requested the ANH to terminate the E&P Contract due to Jauke 1 exploration well in the Fell block; environmental restrictions in the block. These restrictions became apparent • Discovery of the Uaken gas field with successful drilling and testing of the once the National Authority of Environmental Licenses (ANLA) issued the Uaken 1 exploration well in the Fell block; environmental license. As of the date of this annual report, the termination • Average net oil and gas production declined to 2,722 boepd in 2018 from request is under review and the remaining commitment amounts to US$22.3 2,885 boepd in 2017; million. • Proved oil and gas reserves decreased by 9% to 6.8 mmboe at year-end 2018, from 7.5 mmboe at year-end 2017 after producing 0.9 mmboe; Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. • Capital expenditures decreased by 23% to US$7.9 million in 2018 from entered into the Abanico Block association contract. Pacific Rubiales Energy US$10.2 million in 2017; and is the operator of, and has a 100% working interest in, the Abanico Block, • In November 2018 we acquired LGI’s 20% equity interest in our Chilean which covers an area of approximately 26,658 gross acres (103 sq. km). We do subsidiary. not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement initially entered into with Kappa Resources Colombia Limited (now Pacific, who subsequently assigned its participation interest to Cespa de Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A. Operations in Chile Our Chilean assets currently give us access to 808,000 of gross exploratory and productive acres across 5 blocks in a large fully-operated land base across the Magallanes Basin, with existing reserves, production and cash flows. GeoPark 75 The map below shows the location of the blocks in Chile in which we have working interests. The table below summarizes information about the blocks in Chile in which we have working interests as of and for the year ended December 31, 2018. Block Fell Tranquilo Isla Norte Campanario Flamenco Gross acres (thousand acres) Working interest(1) Partners(2) Operator Net proved reserves (mmboe)(3) Production (boepd) Basin Concession expiration year 367.8 100% — GeoPark 6.8 2,708 Magallanes Exploitation: 2032 92.4 50% (4) Pluspetrol GeoPark 97.7 144.2 105.9 60% 50% 50% ENAP GeoPark ENAP GeoPark ENAP GeoPark — — — — — Magallanes Exploitation: 2043 Exploration: 2021 — Magallanes Exploitation: 2044 Exploration: 2021 — Magallanes Exploitation: 2045 Exploration: 2021 14 Magallanes Exploitation: 2044 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in such block. (2) Partners with working interests. (3) As of December 31, 2018. (4) In December 2018, we increased our working interest to 100%. The approval of the agreement is still under the review of the Ministry of Energy. 76 GeoPark 20F Fell Block Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks) In 2006, we became the operator and 100% interest owner of the Fell Block. In the first and second quarters of 2012, we entered into three CEOPs with When we first acquired an interest in the Fell Block in 2002, it had no material ENAP and Chile granting us working interests in the Isla Norte, Campanario oil and gas production. Since then, we have completed more than 1,100 sq. and Flamenco Blocks, located in the center-north of the Tierra del Fuego km of 3D seismic surveys and drilled 117 exploration and development wells. Province of Chile. We are the operator of all three of these blocks, with In the year ended December 31, 2018, we produced an average of 2,708 working interests of 60%, 50% and 50%, respectively. We believe that boepd, in the Fell Block, consisting of 29% oil. these three blocks, which collectively cover 347,700 gross acres (1,407 sq. km) and are geologically contiguous to the Fell Block, represent strategic The Fell Block has an area of approximately 368,000 gross acres (1,488 sq. acreage with resource potential. We have committed to paying 100% of the km) and its center is located approximately 140 km northeast of the city of required minimum investment under the CEOPs covering these blocks, in an Punta Arenas. It is bordered on the north by the international border between aggregate amount of US$101.4 million through the end of the first exploratory Argentina and Chile and on the south by the Magellan Strait. periods for these blocks, which includes our covering of ENAP’s investment commitment corresponding to its working interest in the blocks. From 2006 through August 2011, we successfully explored and developed the Fell Block, which allowed us to transition approximately 84% of the Fell Flamenco Block. We are the operator of, and have a 50% working interest in, Block’s area from an exploration phase into an exploitation phase, which we the Flamenco Block, in partnership with ENAP. The block covers approximately expect will last through 2032. During the exploration phase, we exceeded the 105,900 gross acres (428 sq. km). In June 2013, we discovered a new oil and minimum work and investment commitment required under the Fell Block gas field in the block following the successful testing of the Chercán 1 well, CEOP by more than 75 times. There are no minimum work and investment the first well drilled by us in Tierra del Fuego. As of March 31, 2019, we had commitments under the Fell Block CEOP associated with the exploitation completed 100% of the committed 570 sq. km of 3D seismic surveys and the phase. drilling activities for the first exploration period under the CEOP governing the Flamenco Block. In the year ended December 31, 2018, we produced an The Fell Block is located in the north-eastern part of the Magallanes Basin. average of 14 boepd in the Flamenco Block. The principal producing reservoir is composed of sandstones in the Springhill formation, at depths of 2,200 to 3,500 meters. Additional reservoirs have On June 30, 2017, the Chilean Ministry accepted our proposal to extend the been discovered and put into production in the Fell Block—namely, Tobífera second exploratory period for an additional period of 18 months. As of the formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper date of this annual report, US$2.1 million investment commitments related Tertiary and Upper Cretaceous sandstones, at depths of 700 to 2,000 meters. to this block (corresponding to one exploratory well) remain outstanding and will be entirely assumed by us. On December 20, 2018, we proposed to Our geosciences team identified and developed an attractive inventory of extend the second exploratory period for an additional period of 18 months, prospects and drilling opportunities for both exploration and development in ending November 7, 2020. As of the date of this annual report the Chilean the Fell Block. Ministry has not replied. During 2018, we successfully drilled and completed the Jauke X-1 exploration Isla Norte Block. We are the operator of and have a 60% working interest in well. The well is in production, and the gas is being sold to Methanex through partnership with ENAP in the Isla Norte Block, which covers approximately a long-term gas contract. In addition, we continued to focus on maintaining 97,650 gross acres (395 sq. km). As of March 31, 2019, we had completed production levels, and reducing production, operating costs and workover 100% of the committed 350 sq. km of 3D seismic surveys and drilled one costs. exploratory well, which represents the first oil discovery within the block. As of the date of this annual report, outstanding investment commitments of The Jauke gas field is part of the large Dicky geological structure in the Fell US$2.9 million related to this block correspond to two exploratory wells to be block and has the potential for multiple development drilling opportunities. executed before May 7, 2019. Petrophysical analysis also indicates hydrocarbon potential in the shallower El Salto formation which will be tested in the future. Our 2019 work plan includes Campanario Block. We are the operator of, and have a 50% working interest the drilling of an additional well. in, the Campanario Block, in partnership with ENAP. The block covers approximately 144,150 gross acres (583 sq. km). As of March 31, 2019, we The Fell Block also contains the Estratos con Favrella shale reservoir, which we had completed 100% of the committed 578 sq. km of 3D seismic surveys and believe represents a high-potential, unconventional resource play for shale oil, have also drilled five exploratory wells, including the Primavera Sur 1 well that as a broad area within Fell Block (1,000 sq. km) which appears to be in the oil marks the first discovery of an oil field on the Campanario Block in addition window for this play. to one development well. As of the date of this annual report, outstanding GeoPark 77 investment commitments of US$4.8 million related to this block correspond The map below shows the location of our concessions in Brazil in which we to three exploratory wells to be executed before July 10, 2019. have a current or future working interest, including the BCAM-40 Concession and the concessions from bidding rounds 11, 12, 13 and 14. Tranquilo Block. We completed a seismic program consisting of 163 sq. km of 3D seismic and 371 sq. km of 2D seismic survey work, and drilled four wells, including the Palos Quemados and Marcou Sur well. We discovered gas in the El Salto formation of the Palos Quemado well. At the Palos Quemados well, we completed a 22-week commercial feasibility test aimed at defining its productive potential. As the test was not conclusive, we were granted permission by the Chilean Ministry of Energy to extend the testing period for an additional six months. Upon such testing period, we kept 4 provisional protection areas, which enabled continued analysis of the area prior the declaration of its commercial viability for a period of 5 years. On January 17, 2013, we formally announced to the Chilean Ministry of Energy our decision not to proceed with the second exploratory period and to terminate the exploratory phase of the Tranquilo Block CEOP. Subsequently, we relinquished all areas of the Tranquilo Block, except for a remaining area of 92,417 gross acres, for the exploitation of the Renoval, Marcou Sur, Estancia Maria Antonieta and Palos Quemados Fields, which we have identified as the areas with the most potential for prospects in the block. In November 2017, we proposed to the Ministry of Energy to extend the period to declare the commerciality of discoveries in the areas of Palos Quemados, Maria Antonieta and Marcou Sur for an additional period of 24 months. In February 2018, the Ministry approved our proposal. In December 2018, we increased our working interest to 100%. The approval of the agreement with Pluspetrol in connection with this change is still under review by the Ministry of Energy. Operations in Brazil (1) The PN-T-597 Block is subject to an injunction and our bid for the concession has been suspended. See “Item 3. Key Information—D. Our Brazilian assets currently give us access to 68,600 of gross exploratory Risk factors—Risks relating to our business—The PN-T-597 Concession and productive acres across 7 blocks (6 exploratory blocks and the BCAM-40 Agreement in Brazil may not close.” Concession, which is in production phase) in an attractive oil and gas geography. Highlights of the year ended December 31, 2018 related to our operations in Brazil included: • Average net oil and gas production of 2,925 boepd (99% gas) in the year ended December 31, 2018, as compared to 2,910 boepd in 2017; • Capital expenditures decreased by 36% to US$2.3 million in 2018 from US$3.6 million in 2017; and • Praia dos Castelhanos 1 exploration well was drilled in the REC- T-128 block to a total depth of 8,431 feet and will be completed and tested in the first half of 2019. 78 GeoPark 20F The following table sets forth information as of December 31, 2018 on our concessions in Brazil in which we have a current or future working interest, including the Manati Field and the concessions from bidding rounds 11, 12, 13 and 14. Concession REC-T 94 POT-T 619 PN-T-597(2) SEAL-T-268 REC-T-128 POT-T-747 POT-T-785 Manati Gross acres (thousand acres) Working interest(1) 7.7 100% 100% 100% 100% 7.9 188.7 7.8 7.6 — — — — GeoPark GeoPark GeoPark GeoPark 70% Geosol GeoPark 6.9 100%(5) 7.9 100%(5) — — GeoPark GeoPark Petrobras; Net proved reserves Production Partners Operator (mmboe) (boepd) Basin Concession expiration year Exploration: 2020 — — — — — — — — Recôncavo Exploitation: 2047 — — — Potiguar Parnaíba Sergipe Alagoas — Recôncavo — — Potiguar Potiguar Camamu- Exploration: 2020 Exploitation: 2045 — Exploration: 2020 Exploitation: 2047 Exploration: 2019 Exploitation: 2045 Exploration: 2018(4) Exploitation: 2045 Exploration: 2023 Exploitation: 2050 22.8 10% Enauta; Brasoil Petrobras 3.0 2,925 Almada Exploitation: 2029 (1) Working interest corresponds to the working interests held by our respective subsidiaries, net of any working interests held by other parties in such of concession agreements—BCAM-40 Concession Agreement.” In September 2009, Petrobras announced the relinquishment of BCAM-40’s exploration area concession. See “Item 3. Key Information—D. Risk factors—Risks relating to within the concession to the ANP, except for the Manati Field and the Camarão our business—The PN-T-597 Concession Agreement in Brazil may not close.” (2) PN-T-597 Block subject to the entry into the concession agreement by the ANP and absence of any legal impediments to signing. As of the date of Norte Field. In August 2018, Petrobras announced the relinquishment of the Camarão Norte Field. this annual report, confirmation remains subject to final signing and local The Manati Field is located 65 km south of Salvador, offshore at a water depth authority approval. See “Item 3. Key Information—D. Risk factors—Risks of 35 meters. The field was discovered in October 2000, and, in 2002, Petrobras relating to our business—The PN-T-597 Concession Agreement in Brazil may declared the field commercially viable. Production began in January 2007. As not close.” (3) A 30% working interest of proposed partners is subject to ANP approval. (4) The exploration period is currently suspended subject to the approval of the environmental license by the ANP. Manati Field of December 31, 2018, 11 wells had been drilled in the Manati Field, 6 of which are productive and connected to a fixed production platform installed at a depth of 35 meters, located 9 km from the coast of the State of Bahia. From the platform, the gas flows by sea and land through a 125 km pipeline to the Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to Petrobras up to a maximum volume as determined in the existing Petrobras Gas Sales Agreement As a result of the Rio das Contas acquisition, we have a 10% working interest (as defined below). In July 2015, we signed an amendment to the existing Gas in the BCAM-40 Concession, which originally included interests in the Manati Sales Agreement with Petrobras that covers 100% of the remaining gas reserves Field and the Camarão Norte Field, and which is located in the Camamu-Almada of the Manati Field. Basin. Petrobras is the operator of, and has a 35% working interest in, the BCAM- 40 Concession, which covers approximately 22,784 gross acres (92.2 sq. km). In Also, in 2015, in order to improve the field gas recovery and production, Manati’s addition to us, Petrobras’ partners in the block are Brasoil and Enauta Energia S.A. consortium built an onshore compression plant that started operating in August (Enauta), with 10% and 45% working interests, respectively. Petrobras operates 2015. The compression plant involved capital expenditures of approximately the BCAM-40 Concession pursuant to a concession agreement with the ANP, US$3.7 million at our working interest and allowed us to classify all existing executed on August 6, 1998. See “—Significant Agreements—Brazil—Overview proved undeveloped reserves as proved developed. GeoPark 79 Some environmental licenses related to operation of the Manati Field relating to our business—The PN-T-597 Concession Agreement in Brazil may production system and natural gas pipeline are expired. However, the operator not close.” submitted, in a timely manner, the request for renewal of those licenses and as such this operation is not in default as long as the regulator does not state its PN-T-597 Concession final position on the renewal. Round 11 Concessions The Parnaiba Basin, which covers an area of approximately 148 million gross acres (600,000 sq. km), is a basin with large underexplored areas. As of December 31, 2018, the basin had two fields in production in the basin. During ANP’s 11th Bid Round, held in May 2013, we were awarded 7 exploratory blocks, of which 2 were in the Reconcavo Basin in the state of In the PN-T-597 Concession we committed R$7.7 million (approximately Bahia and 5 were in the Potiguar Basin in the state of Rio Grande do Norte. US$2.0 million, at the December 31, 2018 exchange rate of R$3.9 to US$1.00) The exploratory phase for these concessions is divided into two exploratory for the first exploratory period, equivalent to 180 km of 2D seismic. periods, the first of which lasts for three years and the second of which is non- obligatory and can last for up to two years. The exploratory phase for this concession is divided into two exploratory In 2016, after fulfilling the committed exploratory commitments and ANP, the first exploratory period lasts four years, and the second exploratory further reevaluation of commercial potential, five exploratory blocks were period, which is optional, can last for up to two years. relinquished to the ANP (REC T 85, POT T 620, POT T 663, POT T 664 and POT T periods. Given that Parnaiba Basin is considered as a “new frontier” area by the 665). REC-T 94 Concession See “Item 3. Key Information—D. Risk factors—Risks relating to our business— The PN-T-597 may not close” and “—D. Risk factors—Risks relating to the countries in which we operate—Our operations may be adversely affected by In the REC-T 94 we committed R$17.6 million (approximately US$ 4.5 million, political and economic circumstances in the countries in which we operate at the December 31, 2018 exchange rate of R$3.9 to US$1.00) during the first and in which we may operate in the future” for more information. exploratory period consisting of drilling two exploratory wells and 31 sq. km of 3D seismic surveys. SEAL-T-268 Concession During the year 2014 we executed a 3D seismic survey. Seismic data US$0.4 million, at the December 31, 2018 exchange rate of R$3.9 to interpretation in 2015 and 2016 defined two well locations, one of which was US$1.00) for the first exploratory period. The exploratory phase for this drilled in 2017. The estimated remaining commitment amounts to US$0.9 concession is divided into two exploratory periods, the first lasting three In the SEAL-T-268 Concession we committed R$1.6 million (approximately million. POT-T 619 Concession years, and the second, which is optional, can last for up to two years. During 2016, an electromagnetic survey acquisition of 70 stations and reprocessing of 58 km of vintage 2D seismic was performed and, after ANP approval In the POT-T 619 Concession we committed investments of R$2.3 million of the extension of the first exploratory phase, we will fulfill part of the (approximately US$0.6 million at the December 31, 2018 exchange rate of remaining committed work program that amounts to US$ 0.2 million. R$3.9 to US$1.00) during the first exploratory period, equivalent to 46 km of 2D seismic work. Round 13 Concessions During the year 2014 we executed a 2D seismic survey. Seismic data exploratory concessions, of which two were in the Potiguar Basin in the state processing was concluded in 2015. After seismic interpretation, we decided to of Rio Grande do Norte and two were in the Reconcavo Basin in the state continue to the second exploratory period in September 2016, which lasts for of Bahia. The exploratory phase for these concessions is divided into two two years with a commitment to drill one exploratory well. The well was drilled exploratory periods, the first of which lasts for three years and the second of during 2018 and was abandoned. There is no pending commitment. which is non-obligatory and can last for up to two years. During ANP’s 13th Bid Round held in October 2015, we were awarded four Round 12 Concessions POT-T-747 and POT-T-882 In November 2013, in the 12th Bid Round, the ANP awarded us two The POT-T-747 and POT-T-882 blocks are located in the Potiguar Basin and concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of encompass an area of 14,829 acres (60 square km). Total commitment to Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in the ANP was R$8.5 million (approximately US$2.2 million, at the December the State of Alagoas. 31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory period and is equivalent to acquiring 70 km of 2D seismic and drilling one For more information, see “Item 3. Key information—D. Risk factors—Risks well. During 2017 3D seismic was reprocessed and a well was drilled in the 80 GeoPark 20F POT-T-747 block during 2018 and was abandoned. All the commitments The Morona Block has DeGolyer and MacNaughton certified net proved related to POT-T-882 were fulfilled as of the date of this annual report. The reserves of 18.5 mmboe as of December 31, 2018, composed of 100% oil. estimated remaining commitment in the POT-T-747 block amounts to US$0.5 The map below shows the location of the Morona Block in Peru. million. REC-T-128 and REC-T-93 Both blocks are part of the Reconcavo Basin and have a combined area of 15,405 acres (62.3 square km). The block REC-T-128 was bid for in partnership with Geosol with a 70% working interest for us and 30% working interest for Geosol. The total commitment to the ANP was R$10.7 million (approximately US$2.7 million at the December 31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory period and consists of acquiring 9 km2 of 3D seismic, drilling one well and performing geochemical analysis at two geological levels. During 2016, regional interpretation studies were performed in the area. Part of the minimum exploratory program of Block REC-T-93 has been fulfilled and approved by ANP with the 3D regional seismic acquisition, which also covered Block REC T 94 (Round 11). During 2018, 3D reprocessing was performed in the REC-T-128 block and we also drilled the Praia dos Castelhanos 1 exploration well that will be completed and tested in the first half of 2019. As of December 31, 2018, the estimated remaining commitment in the REC-T-128 block amounts to US$2.2 million. This commitment was fulfilled in the first quarter of 2019. Upon complete fulfillment of the minimum exploratory work program and the accomplishment of local content commitments, the POT-T-882 and REC-T-93 blocks were relinquished to the ANP in December 2018. Round 14 Concessions During ANP’s 14th Bid Round held in September 2017, we were awarded one exploratory concession, in the Potiguar Basin in the state of Rio Grande do Norte. POT-T-785 The POT-T-785 block covers an area of 7,875 acres in the Potiguar Basin, surrounded by producing fields operated by Petrobras. Total commitment to the ANP was R$1.2 million (US$0.3 million, at the December 31, 2018 exchange rate of R$3.9 to US$1.00) during the first exploratory period and is equivalent to acquiring 4 km2 of 3D seismic and performing geochemical analysis before January 29, 2023. As of December 31, 2018, the estimated remaining commitment in the POT-T-785 block amounts to US$0.1 million. Operations in Peru In October 2014, we entered into an agreement to expand our footprint into Peru (our fifth country platform in Latin America) through the acquisition of Morona Block in a joint venture with Petroperu. GeoPark 81 The table below summarizes information about the block in Peru. Block Morona Gross acres (thousand acres) 1,881 Working interest(1) 75% Net proved reserves Production Operator GeoPark (mmboe) (boepd) Basin 18.5 — Marañon Expiration concession year Exploitation: 2039(2) (1) Corresponds to the initial working interest. Petroperu will have the right to increase its working interest in the block by up to 50%, subject to the recovery revenues associated to future sales. The beginning of such activities is subject to the approval of an environmental impact assessment by the Peruvian of our investments in the block through agreed terms in the Petroperu SPA. environmental authority. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Peru—Morona Block.” (2) The concession will expire twenty (20) years after EIA approval. In accordance with the agreement between us and Petroperu, commitments assumed by GeoPark are subject to certain economical and technical conditions being met. Morona Block The Morona Block covers an area of approximately 1,881 thousand gross acres The third stage, which will be initiated once production has been established, (7,600 sq. km). More than 1 billion barrels of oil have been produced from the is expected to focus on carrying out the full development of the Situche surrounding blocks in the Marañon Basin. Central field, including transportation infrastructure. On October 1, 2014, we entered into an agreement to acquire a 75% working The exploratory program entails drilling one exploratory well. Exploratory interest in the Morona Block in Northern Peru. As stated above, this agreement program capital expenditures will be borne exclusively by us. Expected capital includes a work program to be executed by us. This program includes 3 expenditures in 2019 for the Morona Block are mainly related to flexible phases, and we may decide whether to continue or not at the end of each pipeline installation, temporary access road, location conditioning and the phase. On December 1, 2016, through Supreme Decree N° 031-2016-MEN, Morona Camp dock revamping. These activities are subject to the approval of the Peruvian government approved the amendment to the License Contract the Environmental Impact Study, which is under review by the local authority of Morona Block appointing GeoPark as operator and holder of 75% of the as of the date of this annual report. The approval of the Development License-Contract. Environmental Impact Study is expected by the end of the second quarter of The Morona Block contains the Situche Central oil field, which has been 2019. delineated by two wells (with short term tests of approximately 2,400 and Initially we will hold a 75% working interest in the block. However, according 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the to the terms of the agreement, Petroperu has the right to increase its working Situche Central field, the Morona Block has a large exploration potential interest in the block up to 50%, subject to the recovery of our investments in with several high impact prospects and plays. The Morona Block includes the block by certain agreed factors. geophysical surveys of 2,783 km (2D seismic) and 465 sq. km (3D seismic), and an operating field camp and logistics infrastructure. The area has undergone See “Item 3. Key Information—D. Risk factors—Risks relating to our business— oil and gas exploration activities for the past 40 years, and there exist ongoing Our inability to access needed equipment and infrastructure in a timely association agreements and cooperation projects with the local communities. manner may hinder our access to oil and natural gas markets and generate The expected work program and development plan for the Situche Central oil significant incremental costs or delays in our oil and natural gas production” field is to be completed in three stages. and “—We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including native The goal of the initial two stages is to start production from the two wells communities, where our reserves are located.” already drilled in the field, in order to determine the most effective overall development plan and to begin to generate cash flow. These initial stages require an investment of approximately US$100 million to US$150 million and are expected to be completed in 2020. We have committed to carry Petroperu, by paying its portion of the required investment in these initial phases. In addition, we are required to cover any capital or operational expenditures of Petroperu associated with the project until December 31, 2020. We expect these expenditures to be substantially reimbursed by Petroperu from 82 GeoPark 20F Operations in Argentina The map below shows the location of the blocks in Argentina in which we have working interests as of December 31, 2018. (1) Subject to regulatory approvals. See “—Our operations—Operations in Argentina.” The table below summarizes information about the blocks in Argentina in which we have working interests as of December 31, 2018. Block Puelen Sierra del Nevado Aguada Baguales Puesto Touquet El Porvenir CN-V Los Parlamentos Gross acres (thousand acres) 260.2 1,399.4 44.0 34.2 58.9 57.2 330.9 Working interest(1) 18% 18% 100% 100% 100% 50% 50% Operator Pluspetrol Pluspetrol GeoPark GeoPark GeoPark Wintershall YPF Net proved reserves Production (mmboe) (boepd) — — 3.0 1.0 1.0 — — — — 968 495 372 — — Basin Neuquén Neuquén Neuquén Neuquén Neuquén Neuquén Neuquén Expiration concession year Exploration: 2019 Exploration: 2019 Exploitation: 2025 Exploitation: 2027 Exploitation: 2025 Exploration: 2021 Exploration: 2021 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. GeoPark 83 Highlights of the year ended December 31, 2018 related to our operations in CN-V Block Farm-in Agreement Argentina included: On July 22, 2015, we signed a farm-in agreement with Wintershall for the • Operational takeover of newly acquired Aguada Baguales, El Porvenir and CN-V Block in Argentina, which complements our existing acreage in the Puesto Touquet Blocks in the Neuquén Basin with an average net oil and gas basin. Wintershall is Germany’s largest oil and gas producer and a subsidiary production of 1,835 boepd in 2018; of BASF Group. Under the agreement, we committed to operate during the • Capital expenditures of US$9.0 million in 2018; exploratory phase and receive a 50% working interest in the CN-V Block in • Proved oil and gas reserves of 5.0 mmboe at year-end 2018; and exchange for having to drill and fully fund two exploratory wells for a total of • Acquired new low-cost large exploration acreage, the Los Parlamentos US$10 million. block in the Neuquén Basin, in partnership with YPF S.A. (“YPF”) Neuquén blocks The CN-V Block covers an area of approximately 57.2 thousand gross acres and is located in the Neuquén Basin in southern Argentina. The block has 3D On March 27, 2018, we acquired a 100% working interest and operatorship seismic coverage of 180 sq. km and is adjacent to the producing Loma Alta Sur of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks, which are oil field, a region and play-type well known to our team. The block includes located in the Neuquén Basin, for a total consideration of US$52 million, upside potential in the developing Vaca Muerta unconventional play. less a working capital adjustment of US$ 3.1 million. The blocks include production facilities, such as hydrocarboons treatment, storage, and delivery During 2017, we drilled the first exploratory well, Rio Grande Oeste 1, which infrastructure. resulted in the discovery of Rio Grande Oeste oil field. During 2018, we drilled the second exploratory well, Rio Grande Este 1, which is under evaluation. Los Parlamentos Block Farm-in Agreement With these investments GeoPark Argentina has fulfilled the initial commitment In June 2018, we acquired a 50% working interest in the Los Parlamentos of US$10 million and the operation of the block was transferred to Wintershall. exploratory block in partnership with YPF, the largest oil and gas producer in As of the date of this annual report, the estimated remaining commitment in Argentina. In accordance with the partnership agreement, YPF assumed the the CN-V block for the current exploratory period denominated “Field under operationship of the block and GeoPark assumed a commitment to fund its evaluation”, ending on November 27, 2021, amounts to US$1.3 million at our 50% working interest of one exploratory well and additional 3D seismic, which working interest. amounts to US$6 million at GeoPark’s working interest, over the next three years. Oil and natural gas reserves and production 2014 Mendoza Bidding Round Overview On August 20, 2014, the consortium of Pluspetrol and us was awarded two We have achieved consistent growth in oil and gas reserves from our exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of investment activities since 2006, when we began production in the Fell Block the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa in Chile, followed by successful acquisition, exploration and development Mendocina de Energía S.A. (“EMESA”). activities in other countries in which we have a presence, including Colombia, The consortium consists of Pluspetrol (operator with a 72% working interest), EMESA (non-operator with a 10% working interest) and us (non-operator Our reserves Brazil, Argentina, and Peru. with an 18% working interest). In accordance with the terms of the bidding, The following table sets forth our oil and natural gas net proved reserves as of all of the expenditures related to EMESA’s working interest will be carried by December 31, 2018, which is based on the D&M Reserves Report. Pluspetrol and us proportionately to our respective working interests and will be recovered through EMESA’s participation in future potential production. We have committed to a minimum aggregate investment of US$6.2 million for our working interest, which includes the work program commitment on both blocks during the first three years of the exploratory period. As of December 31, 2018, the remaining commitments in the Sierra del Nevado block for the first exploratory period amount to between US$0.5 and US$1.0 million at our working interest. There is no pending commitment in the Puelen block. 84 GeoPark 20F Net proved reserves As of December 31, 2018 Total net During the year ended December 31, 2018, we had 12.8 mmboe of our Natural proved proved undeveloped reserves from December 31, 2017 converted to proved Oil (mmbbl) gas (bcf ) reserves (mmboe)(1) developed reserves due to development drilling in the Jacana and Tigana % Oil oil fields in the Llanos 34 Block. For further information relating to the Net proved developed Colombia Chile Argentina Brazil 32.3 0.7 2.0 0.1 Total net proved developed 35.1 Net proved undeveloped 42.5 2.6 1.4 18.5 Colombia Chile Argentina Peru Total net proved undeveloped (2) Total net proved (Colombia, Chile, Peru, 1.8 12.0 6.2 17.3 37.3 0.3 8.8 3.2 - 32.6 2.7 3.1 3.0 41.4 42.5 4.1 1.9 18.5 reconciliation of our net proved reserves for the years ended December 31, 2018, 2017 and 2016, please see Table 5 included in Note 37 (unaudited) to our Consolidated Financial Statements. Internal controls over reserves estimation process 99% 26% 65% 3% 85% We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers 100% to ensure the integrity, accuracy and timeliness of data furnished to our 63% 74% independent reserves engineers in their estimation process and who have knowledge of the specific properties under evaluation. Our Director of 100% Exploration, Salvador Minniti, is primarily responsible for overseeing the preparation of our reserves estimates and for the internal control over our 65.0 12.3 67.0 97% reserves estimation. He has more than 35 years of industry experience as an E&P geologist, with broad experience in reserves assessment, field development, exploration portfolio generation and management and Argentina and Brazil) 100.1 49.6 108.4 92% acquisition and divestiture opportunities evaluation. See “Item 6. Directors, Senior Management and Employees—A. Directors and senior management.” (1) We calculate one barrel of oil equivalent as six mcf of natural gas. (2) We plan to put 100% of our reported 2018 year-end proved undeveloped reserves into production through activities to be implemented within five years of initial disclosure. In order to ensure the quality and consistency of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that satisfies the following key control objectives: • estimates are prepared using generally accepted practices and methodologies; We had net proved reserves of 108.4 mmboe at December 31, 2018, compared • estimates are prepared objectively and free of bias; to net proved reserves of 95.7 mmboe as of December 31, 2017. • estimates and changes therein are prepared on a timely basis; The 13.3% increase in net proved reserves in 2018, not including annual • estimates and changes therein are properly supported and approved; and production, is mainly attributable to: • estimates and related disclosures are prepared in accordance with regulatory • Better than expected performance from existing wells from the Tigana and requirements. Jacana fields in the Llanos 34 Block, which added 15.4 mmboe. • Extensions and discoveries that resulted in an increase of 9.9 mmboe due to Throughout each fiscal year, our technical team meets with Independent the Tigana and Jacana appraisal wells and the Tigui oil field discovery in Llanos Qualified Reserves Engineers, who are provided with full access to complete 34 Block, the Jauke gas field discovery in the Fell Block and the gas discovery and accurate information pertaining to the properties to be evaluated and of the Une Formation in the Llanos 32 Block. all applicable personnel. This independent assessment of the internally- • An increase of 5.7 mmboe resulting from the purchase of minerals related generated reserves estimates is beneficial in ensuring that interpretations to the acquisitions of the Aguada Baguales, El Porvenir and Puesto Touquet and judgments are reasonable and that the estimates are free of preparer and blocks. management bias. • An increase of 2.5 mmboe due to higher average oil and gas prices. This was partially offset by: Recognizing that reserves estimates are based on interpretations and • Changes in a previously adopted development plan for the Max, Tua, judgments, differences between the proved reserves estimates prepared by Chachalaca Sur, Tilo, and Jacamar fields in the Llanos 34 Block, resulting in a us and those prepared by an Independent Qualified Reserves Engineer of 6.6 mmboe decrease. 10% or less, in aggregate, are considered to be within the range of reasonable • Lower than expected performance from existing wells in the Fell and Manati differences. Differences greater than 10% must be resolved in the technical Blocks, resulting in a 1.0 mmboe decrease. meetings. Once differences are resolved, the independent Qualified Reserves • Revisions in Peru that resulted in a 1.3 mmbbl decrease. Engineer sends a preliminary copy of the reserves report to be reviewed by GeoPark 85 the Technical Committee and Directors of each country. A final copy of the Report based upon its evaluation. D&M’s primary economic assumptions Reserves Report is sent by the Independent Qualified Reserve Engineer to be in estimates included oil and gas sales prices determined according to SEC approved and signed by the Technical Committee and our CEO and CFO. See guidelines, future expenditures and other economic assumptions (including “Item 6. Directors, Senior Management and Employees—C. Board Practices— interests, royalties and taxes) as provided by us. The assumptions, data, Committees of our board of directors.” methods and procedures used, including the percentage of our total reserves Independent reserves engineers reviewed in connection with the preparation of the D&M Reserves Report were appropriate for the purpose served by such report, and DeGolyer and Reserves estimates as of December 31, 2018 for Colombia, Chile, Brazil, MacNaughton used all methods and procedures as it considered necessary Argentina and Peru included elsewhere in this annual report are based on the under the circumstances to prepare such reports. D&M Reserves Report, dated February 4, 2019 and effective as of December 31, 2018. The D&M Reserves Report, a copy of which has been filed as an However, uncertainties are inherent in estimating quantities of reserves, exhibit to this annual report, was prepared in accordance with SEC rules, including many factors beyond our and our independent reserves engineers’ regulations, definitions and guidelines at our request in order to estimate control. Reserves engineering is a subjective process of estimating subsurface reserves and for the areas and period indicated therein. accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality DeGolyer and MacNaughton, a Delaware corporation with offices in Dallas, of available data and its interpretation. As a result, estimates by different Houston, Moscow, Algiers, Astana and Buenos Aires has been providing engineers often vary, sometimes significantly. In addition, physical factors consulting services to the oil and gas industry since 1936. The firm has such as the results of drilling, testing and production subsequent to the more than 200 professionals, including engineers, geologists, geophysicists, date of an estimate, economic factors such as changes in product prices petrophysicists and economists that are engaged in the appraisal of oil and or development and production expenses, and regulatory factors, such as gas properties, the evaluation of hydrocarbon and other mineral prospects, royalties, development and environmental permitting and concession terms, basin evaluations, comprehensive field studies and equity studies related to may require revision of such estimates. Our operations may also be affected the domestic and international energy industry. DeGolyer and MacNaughton by unanticipated changes in regulations concerning the oil and gas industry restricts its activities exclusively to consultation and does not accept in the countries in which we operate, which may impact our ability to recover contingency fees, nor does it own operating interests in any oil, gas or mineral the estimated reserves. Accordingly, oil and natural gas quantities ultimately properties, or securities or notes of its clients. The firm subscribes to a code recovered will vary from reserves estimates. of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Technology used in reserves estimation Firm. According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated The D&M Reserves Report covered 100% of our total reserves. In with “reasonable certainty” to be economically producible—from a given date connection with the preparation of the D&M Reserves Report, DeGolyer forward, from known reservoirs, and under existing economic conditions, and MacNaughton prepared its own estimates of our proved reserves. In operating methods and government regulations—prior to the time at which the process of the reserves evaluation, DeGolyer and MacNaughton did not contracts providing the right to operate expire, unless evidence indicates independently verify the accuracy and completeness of information and data that renewal is reasonably certain, regardless of whether deterministic or furnished by us with respect to ownership interests, oil and gas production, probabilistic methods are used for the estimation. well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and The project to extract the hydrocarbons must have commenced or the sales of production. However, if in the course of the examination something operator must be reasonably certain that it will commence the project came to the attention of DeGolyer and MacNaughton that brought into within a reasonable time. The term “reasonable certainty” implies a high question the validity or sufficiency of any such information or data, DeGolyer degree of confidence that the quantities of oil and/or natural gas actually and MacNaughton did not rely on such information or data until it had recovered will equal or exceed the estimate. Reasonable certainty can be satisfactorily resolved its questions relating thereto or had independently established using techniques that have been proved effective by actual verified such information or data. DeGolyer and MacNaughton independently production from projects in the same reservoir or an analogous reservoir prepared reserves estimates to conform to the guidelines of the SEC, or by other evidence using reliable technology that establishes reasonable including the criteria of “reasonable certainty,” as it pertains to expectations certainty. Reliable technology is a grouping of one or more technologies about the recoverability of reserves in future years, under existing economic (including computational methods) that have been field tested and have been and operating conditions, consistent with the definition in Rule 4-10(a)(2) demonstrated to provide reasonably certain results with consistency and of Regulation S-X. DeGolyer and MacNaughton issued the D&M Reserves repeatability in the formation being evaluated or in an analogous formation. 86 GeoPark 20F There are various generally accepted methodologies for estimating reserves The following table shows the evolution of total net proved undeveloped including volumetrics, decline analysis, material balance, simulation models (“PUD”) reserves in the year ended December 31, 2018. and analogies. Estimates may be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence) methods. The particular method chosen should be based on Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2017 58.9 the evaluator’s professional judgment as being the most appropriate, given (All amounts shown in mmboe) the geological nature of the property, the extent of its operating history and the quality of available information. It may be appropriate to employ several Plus: Extensions, discoveries and acquisitions: methods in reaching an estimate for the property. -Colombia -Chile Estimates must be prepared using all available information (open and cased -Argentina hole logs, core analyses, geologic maps, seismic interpretation, production/ Less: PUD Reserves converted injection data and pressure test analysis). Supporting data, such as working to proved developed reserves: interest, royalties and operating costs, must be maintained and updated when -Colombia such information materially changes. Plus/less: PUD Reserves revisions and movement to/from other categories: Proved undeveloped reserves As of December 31, 2018, we had 67.0 mmboe in proved undeveloped reserves, an increase of 8.1 mmboe, or 14%, over our December 31, 2017 -Colombia -Chile -Peru proved undeveloped reserves of 58.9 mmboe. Changes for the year ended Total Net Proved Undeveloped (“PUD”) December 31 2018, include (i) an increase of 8.9 mmboe in Colombia due to Reserves at December 31, 2018 the Tigana and Jacana appraisal wells, the Tigui field discovery in the Llanos 34 Block and the gas discovery of the Une Formation in the Llanos 32 Block.; 8.9 0.1 2.0 (12.8) 2.1 (1.4) 9.2 67.0 (ii) an increase of 2.0 mmboe in Argentina due to the purchase of minerals in Production, revenues and price history place related with the Aguada Baguales, El Porvenir and Puesto Touquet fields The following table sets forth certain information on our production of oil acquisitions during 2018; (iii) a decrease of 12.8 mmboe in Colombia due to and natural gas in Colombia, Chile, Brazil and Argentina for each of the years the conversion of proved undeveloped reserves to proved developed reserves ended December 31, 2018, 2017 and 2016. in the Llanos 34 Block; (iv) an increase of 8.2 mmboe in Peru due to revisions in the Morona Block; (v) an increase in Peru of 1.0 mmboe due to the impact of higher average oil prices in the Morona Block (vi) an increase of 8.2 mmboe due to the better than expected performance from existing wells from the Tigana and Jacana fields in the Llanos 34 Block in Colombia partially offset by a removal of 1.4 mmboe of proved undeveloped reserves related to a worse than expected performance in the Fell Block in Chile; (vii) an increase of 0.2 mmboe in Chile due to the Jauke field discovery in the Fell Block and (viii) a decrease in reserves of 6.3 mmboe in Colombia due to changes in a previously adopted development plan in Max, Tua, Chachalaca Sur, Tilo and Jacamar fields in the Llanos 34 Block. Of our 67.0 mmboe of net proved undeveloped reserves, 42.5 mmboe (63%), 4.1 mmboe (6%), 1.9 mmboe (3%) and 18.5 mmboe (28%) were located in Colombia, Chile, Argentina and Peru, respectively. During 2018, we incurred approximately US$37.8 million in capital expenditures in Colombia to convert such proved undeveloped reserves to proved developed reserves. No net proved undeveloped reserves were located in Brazil as of December 31, 2018. GeoPark 87 Average daily production(1) As of December 31 Colombia Chile Brazil 2018 Argentina(4) Colombia Chile Brazil Argentina Colombia Chile 2017 2016 Brazil 28,421 782 42 1,202 21,718 1,000 42 4 15,536 1,380 39 52.6 62.3 79.1 65.0 36.1 45.7 60.1 52.3 24.4 37.0 48.0 740 11,640 17,300 3,796 414 11,317 17,209 2.6 5.4 5.0 5.0 5.9 4.5 5.8 - - 5.6 6.3 22.8 1.6 11.9 24.4 6.1 2.9 9.0 31.2 7.5 38.7 5.6 3.2 8.8 20.3 1.4 7.8 3.2 242.6 10.0 21.7 11.0 252.6 - - 5.4 1.4 6.7 14,964 17,346 3.8 5.0 15.8 1.1 16.9 5.8 2.8 8.5 Oil production Average crude oil production (bopd) Average sales price of crude oil (US$/bbl) (3) Natural Gas production Average natural gas production (mcfpd) Average sales price of natural gas (US$/mcf ) (3) Oil and gas production cost Average operating cost (US$/boe) Average royalties and Other (US$/boe) Average production cost (US$/boe)(2) (1) We present production figures net of interests due to others, but before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes. (2) Calculated pursuant to FASB ASC 932. (3) Averaged realized sales price for gas in 2016 does not include our Argentine and Colombian blocks because our gas operations in those countries were not material during such period. (4) We acquired the Neuquén Blocks in March 2018. Production figures do not include production prior to their acquisition by us. The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Chile, Brazil and Argentina for each of the years ended December 31, 2018, 2017 and 2016. Tigana oil field(1) Jacana oil field(1) Rest of Colombia Chile Brazil Argentina Total Oil Mbbl 4,748.0 3,051.0 1,590.0 280.0 15.0 470.0 2018 Gas Mmcf - - - 3,703.0 5,803.0 1,071.0 Oil Mbbl 2,767.0 2,566.0 1,870.0 347.0 15.0 - 2017 Gas Mmcf - - - 3,745.0 5,763.0 - 10,154.0 10,577.0 7,565.0 9,508.0 Oil Mbbl 2016 Gas Mmcf          1,871.5                     -            1,188.6                     -            2,113.2                     -                502.8          5,293.0               14.0          6,314.0                     -                       -            5,690.1        11,607.0 (1) The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia are separately included in the table above as those oil fields individually contain more than 15% of our total proved reserves as of each of the years indicated above. 88 GeoPark 20F Drilling activities The following table sets forth the exploratory wells we drilled as operators during the years ended December 31, 2018, 2017 and 2016. Exploratory wells(1) As of December 31 Colombia Chile Brazil Argentina Colombia Chile Brazil Argentina Colombia Chile 2018 2017 Productive(2) Gross Net Dry(3) Gross Net Total Gross Net 9.0 4.1 2.0 1.5 11.0 5.6 1.0 1.0 - - 1.0 1.0 1.0 0.7 1.0 1.0 2.0 1.7 - - - - - - 5.0 2.3 1.0 0.5 6.0 2.8 1.0 1.0 - - 1.0 1.0 - - 1.0 1.0 1.0 1.0 1.0 0.5 - - 1.0 0.5 3.0 1.4 - - 3.0 1.4 - - - - - - (1) Includes appraisal wells. (2) A productive well is an exploratory, development, or extension well that is not a dry well. (3) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. The following table sets forth the development wells we drilled as operators during the years ended December 31, 2018, 2017 and 2016. Development wells Colombia Chile Brazil Argentina Colombia Chile Brazil Argentina Colombia Chile 2018 2017 Productive(1) Gross Net Dry(2) Gross Net Total Gross Net 16 7.2 - - 16 7.2 - - - - - - - - - - - - - - - - - - 17.0 7.7 1.0 0.5 18.0 8.2 1.0 1.0 - - 1.0 1.0 - - - - - - - - - - - - 3.0 1.4 - - 3.0 1.4 1.0 1.0 - - 1.0 1.0 (1) A productive well is an exploratory, development, or extension well that is not a dry well. (2) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. 2016 Brazil - - - - - - 2016 Brazil - - - - - - GeoPark 89 Developed and undeveloped acreage mboepd. Of this total production, 81%, 7%, 6% and 6% were in Colombia, The following table sets forth certain information regarding our total gross Chile, Argentina and Brazil, respectively. and net developed and undeveloped acreage in Colombia, Chile, Brazil, Argentina and Peru as of December 31, 2018. Acreage(1) (in thousands of acres) In March 2019, we announced the entry into Ecuador through the acquisition of the Espejo and Perico exploratory blocks in the Intracampos Bid Round in the Oriente Basin located in the north-eastern part of Ecuador. Colombia Chile Perú Brazil Argentina The blocks were awarded to the GeoPark and Frontera consortium (50% Total developed acreage Gross Net 11.6 5.6 6.7 6.7 0.7 0.5 Total undeveloped acreage Gross Net 233.3 120.2 801.3 591.0 1,880.3 1,410.3 Total developed and undeveloped acreage Gross Net 244.9 125.8 808.0 597.7 1,881.0 1,410.8 4.1 0.4 253.2 234.1 257.3 234.5 GeoPark, 50% Frontera) in the form of production sharing contracts. The final award is contingent upon regulatory approvals and the execution of the contracts is expected for the second quarter of 2019. 9.8 9.8 1,844.1 On April 1, 2019, we secured 4,000 bopd through a zero-premium three-way 454.6 structure, with a minimum average price of US$45-US$55 per barrel and a maximum average price of US$79 per barrel, for the period commencing 1,853.9 April 2019 to March 2020. 464.4 (1) Developed acreage is defined as acreage assignable to productive wells. Undeveloped acreage is defined as acreage on which wells have not Marketing and delivery commitments Colombia Our production in Colombia consists primarily of crude oil. Sales for the year been drilled or completed to a point that would permit the production ended December 31, 2018 were made under a long term sales agreement with of commercial quantities of oil or gas regardless of whether such acreage Trafigura. contains proved reserves. Net acreage based on our working interest. Productive wells During 2018, our oil sales were done at wellhead with the delivery point at the truck-loading station at each field. In Colombia, pipelines have minimum The following table sets forth our total gross and net productive wells as of quality conditions for access to the system. Consequently, and because we are February 28, 2019. Productive wells consist of producing wells and wells capable mid to heavy oil producers, loading to the pipeline system requires the use of of producing, including natural gas wells awaiting pipeline connections to diluents which are blended into our crude. Under the Trafigura Agreement, commence deliveries and oil wells awaiting connection to production facilities. we followed agreed priorities for the volumes to be transported through the Gross wells are the total number of producing wells in which we have an ODL Pipeline. For the period from January 1, 2018 to December 31, 2018, interest, and net wells are the sum of our fractional working interests owned in Trafigura bought 100% of our production. In 2018, we amended the Trafigura gross wells. Agreement to include a fixed volume oil sale of 8,000 bopd to Trafigura from Productive wells (1) January to December 2019. Colombia Chile Brazil Peru Argentina and Vasconia differential) and discounts that consider transportation costs and Our oil sales price formula is based on market reference indices (Brent price Oil wells Gross Net Gas wells Gross Net quality adjustments. 117.0 66.4 2.0 0.3 47.0 44.0 50.0 49.0 - - 6.0 0.6 - - - - 167.0 166.5 30.0 30.0 With the expiration of the obligation to sell all of our Colombian production to Trafigura, we have started diversifying our client base in Colombia, allocating sales on a competitive basis to leading industry participants, including traders and other producers. (1) Includes wells drilled by other operators, prior to our commencing operations, and wells drilled in blocks in which we are not the operator. A productive well is Our sales strategy is aimed at securing the highest available pricing for our production while securing a reliable and safe execution. To that end, we focus an exploratory, development, or extension well that is not a dry well. on developing synergies and strategic partnerships with both clients and Present activities the national transport systems, in order to obtain a reduction in costs and increased revenues by making use of the best alternatives available. Such Our average oil and gas production in the first quarter of 2019 was 39,558 is the case of the implementation of an unloading facility at Jaguey Station mboepd, with oil production of 34,358 mbopd and gas production of 5,200 in partnership with Oleoducto de Los Llanos (ODL) in 2015. This unloading 90 GeoPark 20F facility is located 42 km away from the Llanos 34 block and allowed for If we were to lose any one of our key customers in Chile, the loss could reduced trucking distance and associated costs. Additionally, during 2018 we temporarily delay production and sale of our oil and gas in Chile. For a developed a project to connect the Llanos 34 field to the ODL pipeline via a discussion of the risks associated with the loss of key customers, See “Item flowline, which will be operational by the second quarter of 2019, allowing 3. Key Information—D. Risk factors—Risks relating to our business—We sell further cost efficiencies and increased operational reliability. almost all of our natural gas in Chile to a single customer, who has in the past temporarily idled its principal facility” and “—We derive a significant portion of If we were to lose any of our customers, the loss could temporarily delay our revenues from sales to a few key customers.” production and sale of our oil in the corresponding block. However, given the wide availability of customers for Colombian crude, we believe we could Brazil identify a substitute customer to purchase the impacted production volumes. Our production in Brazil consists of natural gas and condensate oil. Natural gas Chile production is sold through a long-term, extendable agreement with Petrobras, which provides for the delivery and transportation of the gas produced in the Our customer base in Chile is limited in number and primarily consists of ENAP Manati Field to the EVF gas treatment plant in the State of Bahia. The contract and Methanex. For the year ended December 31, 2018 we sold 100% of our oil is in effect until delivery of the maximum committed volume or June 2030, production in Chile to ENAP and 99% of our gas production to Methanex, with whichever occurs first. The contract allows for sales above the maximum sales to ENAP and Methanex accounting for 3% and 3%, respectively, of our committed volume if mutually agreed by both seller and buyer. The price total revenues in the same period. for the gas is fixed in reais and is adjusted annually in accordance with the Brazilian inflation index. In July 2015, we signed an amendment to the existing On April 21, 2017, we renewed our sales agreement with ENAP. As part of this Gas Sales Agreement with Petrobras that covers 100% of the remaining gas agreement, ENAP has committed to purchase our oil production in the Fell reserves in the Manati Field. Block in the amounts that we produce, subject to the limitation of available storage capacity at the Gregorio Terminal. The sales agreement provides us The Manati Field is developed via a PMNT-1 production platform, which is with the option to interrupt sales to ENAP periodically if conditions in the connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant export markets allow for more competitive price levels. While the agreement through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd renews automatically on an annual basis, we typically revise the agreement (9.5 mm3 per day). The existing pipeline connects the field’s platform to the every year to reflect changes in the global oil market and make certain EVF gas treatment plant, which is owned by the field’s current concession adjustments based on ENAP’s expenses related to storage at the Gregorio holders. During 2015, in order to improve the field gas recovery and Terminal. production, Manatì’s consortium built an onshore compression plant that started operating in August 2015, which allowed us to classify all existing General commercial conditions of our contract with ENAP have remained proved undeveloped reserves as proved developed as of December 31, 2016. stable over time. We deliver the oil we produce in the Fell Block to ENAP at the The BCAM-40 Concession, which includes the Manati Field, also benefits from Gregorio Terminal, where ENAP assumes responsibility for the oil transferred. the advantages of Petrobras’ size. As the largest onshore and offshore operator ENAP owns two refineries in Chile in the north central part of the country and in Brazil, Petrobras has the ability to mobilize the resources necessary to must ship any oil from the Gregorio Terminal to these refineries unless it is support its activities in the concession. consumed locally. In March 2017, we executed a new gas supply agreement with Methanex purchase agreement with Petrobras, pursuant to which Petrobras has effective from May 1, 2017 to December 31, 2026. Under the agreement, committed to purchase all of our condensate production in the Manati Field, Methanex commits to purchase up to 400,000 SCM/d of gas produced by us. but only in the amounts that we produce, without any minimum or maximum In 2018, due to the decline in gas production, the commitment was reduced deliverable commitment from us. The agreement is valid through December to 315,000 SCM/d. We also hold an option to deliver up to 15% above this 31, 2019, and can be renewed upon an amendment signed by Petrobras and volume. the seller. The condensate produced in the Manati Field is subject to a condensate We gather the gas we produce in several wells through our own flow lines Peru and inject it into several gas pipelines owned by ENAP. The transportation of In Peru, oil production is generally traded on a free market basis and the gas we sell to Methanex through these pipelines is pursuant to a private commercial conditions generally follow international markers, normally WTI contract between Methanex and ENAP. We do not own any natural gas and Brent. As per the Joint Operating Agreement executed with Petroperu, pipelines for the transportation of natural gas. Petroperu has the first option to acquire oil produced by us in the Morona Block by matching any offer received by third parties regarding such production. GeoPark 91 Future production in the Morona Block is expected to be transported through to pay a royalty to the Colombian government based on our production the existing North Peruvian Pipeline to be sold to the domestic or export of hydrocarbons, as of the time a field begins to produce. Under Law 756 markets at the Bayovar port. The North Peruvian Pipeline and the Bayovar of 2002, as modified by Law 1530 of 2012, the royalties we must pay in port are owned and operated by Petroperu, and regulated and supervised by connection with our production of light and medium oil are calculated on a Osinergmin, the regulatory body in the hydrocarbons sector. Transportation field-by-field basis. See Note 32.1 to our Consolidated Financial Statements. rates are negotiated with Petroperu. However, if an agreement cannot be reached between Petroperu and us, transportation rates will be determined Additionally, in the event that an exploitation area has produced amounts in by Osinergmin. The North Peruvian pipeline transported an average of 22,000 excess of an aggregate amount established in the E&P Contract governing bopd in the first 9 months of 2018. On November 27, 2018, crude shipments such area, the ANH is entitled to receive a “windfall profit,” to be paid on the North Line of the North Peruvian Pipeline were interrupted due to a periodically, calculated pursuant to such E&P Contract. blockage by a local community which resulted in a spill. In February 27, 2019, the Peruvian government reached an agreement with the local community In each of the exploration and exploitation periods, we are also obligated that allowed the repairs to be made and the pipeline to restart operations in to pay the ANH a subsoil use fee. During the exploration period, this fee is March 2019. See “Item 3. Risk factors—Risks relating to our business—Our scaled depending on the contracted acreage. During the exploitation period, inability to access needed equipment and infrastructure in a timely manner the fee is assessed on the amount of hydrocarbons produced, multiplied by may hinder our access to oil and natural gas markets and generate significant a specified dollar amount per barrel of oil produced or thousand cubic feet incremental costs or delays in our oil and natural gas production.” of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in Argentina the relevant E&P Contract. All the gas produced in Argentina is sold to Grupo Albanesi, a leading Argentine privately held conglomerate focused on the energy market that Our E&P Contracts are generally subject to early termination for a breach offers natural gas and power supply and transport services to its customers. by the parties, a default declaration, application of any of the contract’s We have an annual agreement in effect from May 2018 through April 2019. unilateral termination clauses or termination clauses mandated by According to local practices, this agreement contains seasonal prices, splitting Colombian law. Anticipated termination declared by the ANH results in between winter and summer prices. the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH. Pursuant to Colombian law, if Our oil sales in Argentina are diversified across clients and delivery points. 30% certain conditions are met, the anticipated termination declared by the ANH of our production in Argentina (2% of consolidated revenues) is sold locally in may also result in a restriction on the ability to engage contracts with the the Neuquén Province and delivered at well-head. The remaining 70% (3% of Colombian government during a certain period of time. See “Item 3. Key consolidated revenues) is sold to major refineries in Argentina and delivered Information—D. Risk factors—Risks relating to our business—Our contracts through pipeline. As usual in the local market, the sales agreements are in obtaining rights to explore and develop oil and natural gas reserves executed for short-term renewable periods from one to three months. are subject to contractual expiration dates and operating conditions, and Significant Agreements Colombia E&P Contracts our CEOPs, E&P Contracts and concession agreements are subject to early termination in certain circumstances.” Llanos 34 Block E&P Contract. Pursuant to an E&P Contract between Unión We have entered into E&P Contracts granting us the right to explore and Temporal Llanos 34 (a consortium between Ramshorn and Winchester Oil operate, as well as working interests in six blocks in Colombia. These E&P and Gas - now GeoPark Colombia SAS) and the ANH that became effective as Contracts are generally divided into two periods: (1) the exploration period, of March 13, 2009 (“Llanos 34 Block E&P Contract”), Unión Temporal Llanos which may be subdivided into various exploration phases and (2) the 34 was granted the right to explore and operate the Llanos 34 Block, and we exploitation period, determined on a per-area basis and beginning on the and Ramshorn were granted a 40% and a 60% working interest, respectively, date we declare an area to be commercially viable. Commercial viability in the Llanos 34 Block. We were also granted the right to operate the Llanos is determined upon the completion of a specified evaluation program 34 Block. On December 16, 2009, Winchester Oil and Gas (now GeoPark or as otherwise agreed by the parties to the relevant E&P Contract. The Colombia) entered into a joint operating agreement with Ramshorn and exploitation period for an area may be extended until such time as such area P1 Energy with respect to our operations in the block. As of the date of this is no longer commercially viable and certain other conditions are met. annual report, the members of the Union Temporal Llanos 34 are GeoPark Colombia SAS with 45%, and Parex Verano Limited with 55% working Pursuant to our E&P Contracts, we are required, as are all oil and gas interest. companies undertaking exploratory and production activities in Colombia, 92 GeoPark 20F We are currently in an additional exploration period (the contract provides two phases: (1) an exploration phase, which is divided into two or more for two optional exploratory phases of 18 months each, in which the exploration periods, and which begins on the effectiveness date of the operator carries out exploratory activities in order to retain areas to relevant CEOP, and (2) an exploitation phase, which is determined on a per- explore) of the Llanos 34 Block E&P Contract with an exploitation program field basis, commencing on the date we declare a field to be commercially in execution over certain areas. The contract also provides for a six-year viable and ending with the term of the relevant CEOP. In order to transition exploration period consisting of two three-year phases. It also provides for a from the exploration phase to an exploitation phase, we must declare a 24-year exploitation period for each commercial area, which begins on the discovery of hydrocarbons to the Ministry of Energy. This is a unilateral date on which such area is declared commercially viable. The exploitation declaration, which grants us the right to test a field for a limited period of period may be extended for periods of up to 10 years at a time until such time for commercial viability. If the field proves commercially viable, we time as the area is no longer commercially viable and certain conditions are must make a further unilateral declaration to the Ministry of Energy. In the met. We have presented evaluation programs to the ANH for the Tilo Field. exploration phase, we are obligated to fulfill a minimum work commitment, We presented the declaration of commerciality of Max, Túa, Tarotaro, Tigana, which generally includes the drilling of wells, the performance of 2D or 3D Jacana and Chachalaca, respectively. seismic surveys, minimum capital commitments and guaranties or letters of credit, as set forth in the relevant CEOP. We also have relinquishment Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are obligations at the end of each period in the exploration phase in respect required to pay a royalty to the ANH based on hydrocarbons produced in the of those areas in which we have not made a declaration of discovery. Llanos 34 Block. See Note 32.1 to our Consolidated Financial Statements. We can also voluntarily relinquish areas in which we have not declared Additionally, we are required to pay a subsoil use fee to the ANH. ANH phase, we generally do not face formal work commitments, other than the also has the right to receive an additional fee when prices for oil or gas, development plans we file with the Chilean Ministry of Energy for each field as the case may be, exceed the prices set forth in the Llanos 34 Block E&P declared to be commercially viable. discoveries of hydrocarbons at any time, at no cost to us. In the exploitation Contract. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. Our CEOPs provide us with the right to receive a monthly remuneration from Chile, payable in petroleum and gas, based either on the amount of In accordance with the Llanos 34 Block operation contract, when the petroleum and gas production per field or according to Recovery Factor, accumulated production of each field, including the royalties’ volume, which considers the ratio of hydrocarbon sales to total cost of production exceeds 5 million barrels and the WTI exceeds a defined base price, the (capital expenditures plus operating expenses). Pursuant to Chilean law, Company should deliver to ANH a share of the production net of royalties in the rights contained in a CEOP cannot be modified without consent of the accordance with an established formula. See Note 32.1 to our Consolidated parties. Financial Statements. Our CEOPs are subject to early termination in certain circumstances, which Winchester and Luna Stock Purchase Agreement vary depending upon the phase of the CEOP. During the exploration Pursuant to the stock purchase agreement entered into on February 10, 2012 phase, Chile may terminate a CEOP in circumstances including a failure (the “Winchester Stock Purchase Agreement”), we agreed to pay the Sellers a by us to comply with minimum work commitments at the termination total consideration of US$30.0 million, adjusted for working capital. Additionally, of any exploration period, or a failure to communicate our intention to under the terms of the Winchester Stock Purchase Agreement, we are obligated proceed with the next exploration period 30 days prior to its termination, to make certain payments to the Sellers based on the production and sale of a failure to provide the Chilean Ministry of Energy the performance bonds hydrocarbons discovered by exploration wells drilled after October 25, 2011. required under the CEOP, a voluntary relinquishment by us of all areas Once the maximum earn-out amount is reached, we pay the Sellers quarterly under the CEOP or a failure by us to meet the requirements to enter into overriding royalties in an amount equal to 4% of our net revenues from any new the exploitation phase upon the termination of the exploration phase. In discoveries of oil. For the year ended December 31, 2018, we accrued and paid the exploitation phase, Chile may terminate a CEOP if we stop performing US$20.6million and US$19.1 million with regards to this agreement. any of the substantial obligations assumed under the CEOP without Chile CEOPs cause and do not cure such nonperformance pursuant to the terms of the concession, following notice of breach from the Chilean Ministry of Energy. Additionally, Chile may terminate the CEOP due to force majeure Currently, we have five CEOPs in effect with Chile, one for each of the circumstances (as defined in the relevant CEOP). If Chile terminates a CEOP blocks in which we operate, which grant us the right to explore and exploit in the exploitation phase, we must transfer to Chile, free of charge, any hydrocarbons in these blocks, determine our working interests in the productive wells and related facilities, provided that such transfer does not blocks and appoint the operator of the blocks. These CEOPs are divided into interfere with our abandonment obligations and excluding certain pipelines GeoPark 93 and other assets. Other than as provided in the relevant CEOP, Chile cannot remuneration fraction to a minimum of 75% when the recovery factor is 2.5 unilaterally terminate a CEOP without due compensation. See “Item 3. Key times the total accumulated expenses. Information—D. Risk factors—Risks relating to our business—Our contracts in obtaining rights to explore and develop oil and natural gas reserves Neuquén Exploitation Concessions. After receiving authorization in March 27, are subject to contractual expiration dates and operating conditions, and 2018 from the Province of Neuquén under Provincial Decree 266/2018, we our CEOPs, E&P Contracts and concession agreements are subject to early closed the acquisition of a 100% interest in the Aguada Baguales, El Porvenir termination in certain circumstances.” and Puesto Touquet hydrocarbon exploitation concessions from Pluspetrol S.A., together with an ancillary transportation concession over a natural gas Fell Block CEOP . On November 5, 2002, we acquired a percentage of rights and pipeline from Puesto Touquet to Plaza Huincul, all in the Neuquén Basin in interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and Argentina. These concessions had been originally granted to Pluspetrol S.A. on May 10, 2006, we became the sole owners, with 100% of the rights and for a term of 25 years in 1990 (Aguada Baguales and El Porvenir Blocks) and interest in the Fell Block CEOP. Chile had originally entered into a CEOP for the 1992 (Puesto Touquet Block). In 2008, the Province of Neuquén granted a Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April 29, 1997, ten year extension of these concessions in consideration of an investment which had an effective date of August 25, 1997. The Fell Block CEOP grants us program which included development, exploration and environmental the exclusive right to explore and exploit hydrocarbons in the Fell Block and remediation programs and a payment of a cash bonus in proportion to the has a term of 35 years, beginning on the effective date. The Fell Block CEOP in-situ hydrocarbon reserves of the blocks. At least one year prior to the end provided for a 14-year exploration period, composed of numerous phases that of the current ten year extension period, we are entitled to request a further ended in 2011, and an up-to-35-year exploitation phase for each field. ten year extension to these concessions in consideration for continued The Fell Block CEOP provides us with a right to receive a monthly retribution royalty) and a cash bonus equal to 2% of the then existing in-situ reserves. investments, an incremental 3% royalty (resulting in an aggregate 18% from Chile payable in petroleum and gas, based on the following per- field formula: 95% of the oil produced in the field, for production of up to Under these concessions, we are entitled to the exclusive right to develop 5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for the entire acreage of the concessions, produce, freely dispose and market all production of up to 882.9 mmcfpd. In the event that we exceed these levels hydrocarbons we lift under a royalty tax system. of production, our monthly retribution from Chile will decrease based on a sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the LGI Termination Agreement oil and 60% of the gas that we produce per field. Pursuant to the sale and purchase agreement entered into on November 28, 2018 (the “LGI Termination Agreement”), we agreed to pay LGI a total TDF Blocks CEOPs . After an international bidding process led by ENAP and consideration of up to US$126 million for its entire equity interest in Geopark the Chilean Ministry of Energy, in March and April, 2012, we, together with Chile, Geopark TdF and Geopark Colombia Coöperatie U.A. The acquisition ENAP, signed 3 new CEOPs for the Isla Norte, Campanario and Flamenco price includes a fixed payment of US$81 million paid at closing, plus two Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region. equal installments of US$15 million each, to be paid in June 2019 and June Our working interest is 60% in Isla Norte and 50% in Campanario and 2020, respectively, and three contingent payments of US$5 million each, Flamenco Blocks. The CEOPs have a term of 32 years, with an initial which could accrue over the next three years, subject to certain production exploration phase which last for 7 years, including a first exploration period thresholds being exceeded in the Llanos 34 Block. As a consequence of the of 3 years in which we are committed to developing several exploration LGI Termination Agreement we have become sole shareholder of the entities activities including 1,500 square kilometers of 3D seismic registration, and referred to above. See “Item 7. Major Shareholders and Related Parties—B. the drilling of 21 exploratory wells. Related Party Transactions—LGI Termination Agreement.” The hydrocarbon discoveries opened up an exploitation phase that lasts Brazil up to 32 years. We discovered hydrocarbon fields in the 3 blocks, starting in Overview of concession agreements 2013 in the Flamenco Block, and in 2014 in both Campanario and Isla Norte The Brazilian oil and gas industry is governed mainly by the Brazilian Blocks. The CEOPs provide us with a right to receive a remuneration payable Petroleum Law, which provides for the granting of concessions to operate by means of a fraction of the production sold, which in the TDF Blocks is petroleum and gas fields in Brazil, subject to oversight by the ANP. A based on a formula depending on the recovery of the total accumulated concession agreement is divided into two phases: (1) exploration and (2) expenses incurred (capital expenditure plus operational expenditure plus development and production. The exploration phase, which is further divided administrative and general expenses). While the recovery factor is less than into two subsequent exploratory periods, the first of which begins on the date 1.0, the remuneration is 95% of the hydrocarbons produced, either oil or gas. of execution of the concession agreement, can last from three to eight years If the recovery factor surpasses 1.0, a formula applies reducing gradually the (subject to earlier termination upon the total return of the concession area 94 GeoPark 20F or the declaration of commercial viability with respect to a given area), while • a special participation fee; the development and production phase, which begins for each field on the • royalties; and date a declaration of commercial viability is submitted to the ANP, can last up • taxes. to 27 years. Upon each declaration of commercial viability, a concessionaire must submit to the ANP a development plan for the field within 180 days. The Rental fees for the occupation and maintenance of the concession areas are concessions may be renewed for an additional period equal to their original payable annually. For purposes of calculating these fees, the ANP takes into term if renewal is requested with at least 12 months’ notice, and provided consideration factors such as the location and size of the relevant concession, the that a default under the concession agreement has not occurred and is then sedimentary basin and the geological characteristics of the relevant concession. continuing. Even if obligations have been fulfilled under the concession agreement and the renewal request was appropriately filed, renewal of the A special participation fee is an extraordinary charge that concessionaires must concession is subject to the discretion of the ANP. pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulations, and is The main terms and conditions of a concession agreement are set forth payable on a quarterly basis for each field from the date on which extraordinary in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of production occurs. This participation fee, whenever due, varies between 0% the concession area; (2) validity and terms for exploration and production and 40% of net revenues depending on (1) the volume of production and (2) activities; (3) conditions for the return of concession areas; (4) guarantees to whether the concession is onshore or in shallow water or deep water. Under be provided by the concessionaire to ensure compliance with the concession the Brazilian Petroleum Law and applicable regulations issued by the ANP, the agreement, including required investments during each phase; (5) penalties special participation fee is calculated based on the quarterly net revenues of in the event of noncompliance with the terms of the concession agreement; each field, which consist of gross revenues calculated using reference prices (6) procedures related to the assignment of the agreement; and (7) rules for established by the ANP (reflecting international prices and the exchange rate for the return and vacancy of areas, including removal of equipment and facilities the period) less: and the return of assets. Assignments of participation interests in a concession • royalties paid; are subject to the approval of the ANP, and the replacement of a performance • investment in exploration; guarantee is treated as an assignment. • operational costs; and • depreciation adjustments and applicable taxes. The main rights of the concessionaires (including us in our concession agreements) are: (1) the exclusive right of drilling and production in the The Brazilian Petroleum Law also requires that the concessionaire of onshore concession area; (2) the ownership of the hydrocarbons produced; (3) the fields pay to the landowners a special participation fee that varies between right to sell the hydrocarbons produced; and (4) the right to export the 0.5% to 1.0% of the net operational income originated by the field production. hydrocarbons produced. However, a concession agreement set forth that, in the event of a risk of a fuel supply shortage in Brazil, the concessionaire BCAM-40 Concession Agreement . On August 6, 1998, the ANP and Petrobras must fulfill the needs of the domestic market. In order to ensure the domestic executed the concession agreement governing the BCAM-40 Concession, or supply, the Brazilian Petroleum Law granted the ANP the power to control the the BCAM-40 Concession Agreement, following the first round of bidding, export of oil, natural gas and oil products. referred to as Bid Round Zero, under the regime established by the Brazilian Petroleum Law. The exploitation phase will end in November 2029. On Among the main obligations of the concessionaire are: (1) the assumption of September 11, 2009, Petrobras announced the termination of BCAM-40 costs and risks related to the exploration and production of hydrocarbons, Concession’s exploration phase and the return of the exploratory area of the including responsibility for environmental damages; (2) compliance with the concession to the ANP, except for the Manati Field and the Camarão Norte Field. requirements relating to acquisition of assets and services from domestic suppliers; (3) compliance with the requirements relating to execution of the Under the BCAM-40 Concession Agreement, the ANP is entitled to a monthly minimum exploration program proposed in the winning bid; (4) activities for royalty payment equal to 7.5% of the production of oil and natural gas in the the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments concession area. In addition, in case the special participation fee of 10% shall for government participation; and (7) responsibility for the costs associated be applicable for a field in any quarter of the calendar year, the concessionaire with the deactivation and abandonment of the facilities in accordance with is obliged to make qualified research and development investments equivalent Brazilian law and best practices in the oil industry. to one percent of the field’s gross revenue. Area retention payments are also applicable under the concession agreement. We acquired Rio das Contas’ 10% A concessionaire is required to pay to the Brazilian government the following: participation interest in the BCAM-40 Concession on March 31, 2014. • a license fee; • rent for the occupation or retention of areas; GeoPark 95 Rounds 11, 12, 13 and 14 Concession Agreements. is valid until the earlier of Petrobras’ receipt of this total contractual quantity Under the Rounds 11, 12, 13 and 14 Concession Agreements, the ANP is or June 30, 2030. The agreement may not be fully or partially assigned except entitled to a monthly royalty corresponding to up to 10% of the production upon execution of an assignment agreement with the written consent of the of oil and natural gas in the concession area, in addition to the special other parties, which consent may not be unreasonably withheld provided that participation fee described above, the payment for the occupation of the certain prerequisites have been met. concession area of approximately R$7,600 per year and the payment to the owners of the land of the concession equivalent to one percent of the oil and The agreement provides for the provision of “daily contractual quantities” to natural gas produced in the concession area. Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until 2030. The parties may agree to lower volumes as dictated by Manati Field’s During bidding, a work program offer is made in the form of work units and depletion. Pursuant to the agreement, the base price is denominated in reais the ANP asks for a guarantee of a monetary amount proportional to the and is adjusted annually for inflation pursuant to the general index of market offered units. However, depending on the work performed by the operator, prices (IGPM). Additionally, the gas price applicable on a given day is subject the actual work program investment might have a different value to the to reduction as a result of the gas quantity acquired by Petrobras above the guaranteed value. volume of the annual TOP commitment (85% of the daily contracted quantity) in effect on such day. The Petrobras Natural Gas Purchase Agreement provides Overview of consortium agreements that all of the Manati Field’s daily production be sold to Petrobras. A consortium agreement is a standard document describing consortium members’ respective percentages of participation and appointment of Peru the operator. It generally provides for joint execution of oil and natural Morona Block gas exploration, development and production activities in each of the On October 1, 2014, we entered into an agreement with Petroperu to acquire concession areas. These agreements set forth the allocation of expenses for an interest in and operate the Morona Block, located in Northern Peru. We will each of the parties with respect to their respective participation interests assume a 75% working interest of the Morona Block, with Petroperu retaining in the concession. The agreements are supplemented by joint operating a 25% working interest. On December 1, 2016, through Supreme Decree N° agreements, which are private instruments that typically regulate the 031-2016-MEN the Peruvian government approved the amendment to the aggregation of funds, the sharing of costs, mitigation of operational risks, License Contract of Block 64 (Morona Block) appointing GeoPark as operator preemptive rights and the operator’s activities. and holder of 75% of the Contract. An important characteristic of the consortia for exploration and production In Peru, there is a 5-20% sliding scale royalty rate, depending on production of oil and natural gas that differs from other consortia (Article 278, paragraph levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For 1, of the Brazilian Corporate Law) is the joint liability among consortium production between 5,000 and 100,000 bopd there is a linear sliding scale members as established in the Brazilian Petroleum Law (Article 38, item II). between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%. BCAM-40 Consortium Agreement See “Item 4. Information on the Company—B. Business Overview—Our On January 14, 2000, Petrobras, Enauta and Petroserv entered into a operations—Operations in Peru—Morona Block.” consortium agreement, or the BCAM-40 Consortium Agreement, for the performance of the BCAM-40 Concession Agreement. Petrobras is the Argentina operator of the BCAM-40 concession, with a 35% participation interest. Overview of exploration permits Enauta, Brasoil and Rio das Contas have a 45%, 10% and 10% participation Our exploration permits grant to us and our partners the exclusive right to interest, respectively. The BCAM-40 Consortium Agreement has a specified explore for hydrocarbons and declare a commercial discovery within the acreage term of 40 years, terminating on January 14, 2040 and, at the time the of our permits. Our exploration permits are made up of three subperiods, each obligations undertaken in the agreement are fully completed, the parties lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years. will have the right to terminate it. The BCAM-40 Concession consortium has also entered into a joint operating agreement, which sets out the rights and We are bound to pursue specific minimum work or investment commitments obligations of the parties in respect of the operations in the concession. during each of the subperiods of each exploration permit. Such exploration Petrobras Natural Gas Purchase Agreement works are valued in work units assigned to each particular type of work under Enauta, GeoPark Brasil, Brasoil and Petrobras are party to a natural gas the applicable bidding conditions. purchase agreement providing for the sale of natural gas by Enauta, GeoPark Work and investment programs for the permits are required to be assured by Brasil and Brasoil to Petrobras, in an amount of 812 billion cubic feet (“bcf”) issuing a performance bond for the value of the committed work plan. over the term of agreement. The Petrobras Natural Gas Purchase Agreement 96 GeoPark 20F Under the terms of our exploration permits and concession agreements, we are Title to properties entitled to our proportionate share of the hydrocarbons production lifted from In each of the countries in which we operate, the state is the exclusive owner each block. The Province of Mendoza’s state owned company, EMESA, has a 10% of all hydrocarbon resources located in such country and has full authority carried interest in each of the Puelen and Sierra del Nevado permits and any to determine the rights, royalties or compensation to be paid by private future exploitation concessions, while there is no governmental participation investors for the exploration or production of any hydrocarbon reserves. In in the CN-V Block. During the term of our exploration permits, we are also Chile, the Republic of Chile grants such rights through a CEOP. In Colombia, required, under Argentine law, to pay a 15% royalty to the province on both oil the Republic of Colombia grants such rights through E&P Contracts or and gas sales. In case we progress to an exploitation concession, the applicable contracts of association. In Argentina, the Argentine Republic grants such royalty rate will reduce to a 12% royalty. We also pay annual surface rental rights through exploitation concessions. In Brazil, the Federative Republic fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and of Brazil grants such rights pursuant to concession agreements. See “Item 3. Resolution 588/98 of the Argentine Secretariat of Energy and Decree 1454/2007, Key Information—D. Risk factors—Risks relating to the countries in which and certain landowner fees. we operate—Oil and natural gas companies in Colombia, Chile, Brazil, Argentina and Peru do not own any of the oil and natural gas reserves in Our Argentine exploration permits have no change of control provisions, though such countries.” Other than as specified in this annual report, we believe that any assignment of these concessions is subject to the prior authorization by the we have satisfactory rights to exploit or benefit economically from the oil executive branch of the Province of Mendoza and rights of first refusal in favor and gas reserves in the blocks in which we have an interest in accordance of our partners and EMESA, in the case of the Puelen and Sierra del Nevado with standards generally accepted in the international oil and gas industry. permits. Each of these permits or future concessions can be terminated for Our CEOPs, E&P Contracts, contracts of association, exploitation concessions default in payment obligations and/or breach of material statutory or regulatory and concession agreements are subject to customary royalty and other obligations. We are subject to the obligation to relinquish at least 50% of the interests, liens under operating agreements and other burdens, restrictions acreage of each exploration permit at the end of each exploration subperiod. We and encumbrances customary in the oil and gas industry that we believe may also voluntarily relinquish acreage to the provincial authorities. do not materially interfere with the use of or affect the carrying value of our Our Argentine exploration permits are governed by the laws of Argentina and our business—We are not, and may not be in the future, the sole owner or the resolution of any disputes must be sought in the Mendoza Provincial Courts. operator of all of our licensed areas and do not, and may not in the future, interests. See “Item 3. Key Information—D. Risk factors—Risks relating to If and when we make a commercial discovery in one or more of our exploration may not be able to control the timing of exploration or development efforts, permits, we will have the right to request and obtain an exploitation concession associated costs, or the rate of production of any non-operated and, to an to produce hydrocarbons in the block for 25 years, with an optional extension extent, any non-wholly-owned, assets.” hold all of the working interests in certain of our licensed areas. Therefore, we of up to 10 years. We also receive the right to be granted a 35-year oil transport concession to build and make use of pipelines or other transport facilities Our customers beyond the boundaries of the concession. In Colombia, our primary customer is Trafigura, and who represented 82% of our total revenues for the year ended December 31, 2018. In Chile, our primary Additionally, oil and gas producers in Argentina must grant a privilege to the customers are ENAP and Methanex. As of December 31, 2018, ENAP purchased domestic market to the detriment of the export market, including hydrocarbon all of our Chilean oil and condensate production and Methanex purchased export restrictions, domestic price controls, export duties and domestic market almost all of our natural gas production in Chile, and represented 3% and 3%, supplier obligations. Pluspetrol Asset Purchase Agreement respectively, of our total revenues for the year ended December 31, 2018. In Brazil, all of our hydrocarbons in Manati are sold to Petrobras. In Argentina, all Pursuant to the APA that we entered into on December 18, 2017 with the gas produced is sold to Grupo Albanesi and represented 1% of our total Pluspetrol, we agreed to acquire a 100% working interest and operatorship revenues. Our oil production in Argentina is split between local buyers in the of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina Neuquén Province, delivered at well-head (2% of consolidated revenues) and for a total consideration of $52 million. The blocks include estimated oil and major refineries, delivered through pipeline (3% of consolidated revenues). In gas production of 2,700 boepd (70% light oil and 30% gas), 137,000 acres Peru, our primary customers are local refineries (Petroperu or Repsol) or the well-positioned in the Neuquén Basin and production facilities, including export market. Petroperu, has the first option to acquire the oil produced by us hydrocarbons treatment, storage, and delivery infrastructure. in the Morona Block by matching any offer received by third parties regarding We paid the consideration using proceeds from the offering of the Notes due 2024. The acquisition of the blocks closed on March 27, 2018. Seasonality such production. Although there is some historical seasonality to the prices that we receive GeoPark 97 for our production, the impact of such seasonality has not been material. regulated materials; and human health and safety. These laws and regulations Seasonality has also not played a significant role in our ability to conduct our may, among other things: operations, including drilling and completion activities. • require the acquisition of various permits or other authorizations or the However, as the Morona Block is located in a remote area, the development closure plans) before seismic or drilling activity commences; of the project depends on significant infrastructure being built which can • enjoin some or all of the operations of facilities deemed not in compliance be impacted by seasonal weather patterns, including rain. Since there are with permits; no roads available in the surrounding area, logistics will be performed by • restrict the types, quantities or concentration of various substances that helicopters or barges during specific seasons of the year. can be released into the environment related to oil and natural gas drilling, preparation of environmental assessments, studies or plans (such as well We take such seasonality into account in planning for and conducting our • require establishing and maintaining bonds, reserves or other operations, such that the impact on our overall business is not material. commitments to plug and abandon wells; production and transportation activities; Our competition • limit or prohibit seismic and drilling activities in certain locations lying within or near protected or environmentally sensitive areas; The oil and gas industry is competitive, and we may encounter strong • require preventative measures to mitigate pollution from our operations, competition from other independent operators and from major state-owned which, if not undertaken, could subject us to substantial penalties; and oil companies in acquiring and developing licenses in the countries where we • require us to maintain a safe and healthy working environment for all operate or plan to operate. employees, contractors and visitors in accordance with applicable regulations and industry best practices. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be These laws and regulations may also restrict the rate of oil and natural gas able to pay more for desirable oil and natural gas assets, or to evaluate, bid production below the rate that would otherwise be possible. Compliance for and purchase a greater number of licenses than our financial or personnel with these laws can be costly. The regulatory burden on the oil and resources will permit. Furthermore, these companies may also be better able gas industry increases the cost of doing business in the industry and to withstand the financial pressures of unsuccessful wells, sustained periods of consequently affects profitability. volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the Public interest in the protection of the environment continues to increase. burdens resulting from changes in relevant laws and regulations, which may Drilling in some areas has been opposed by certain community and adversely affect our competitive position. See “Item 3. Key Information—D. environmental groups and, in other areas, has been restricted. Risk factors—Risks relating to our business—Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, Climate change acquire properties and prospects, market oil and natural gas and secure Both our operations and the combustion of oil and natural gas-based trained personnel.” products results in the emission of greenhouse gases, which may contribute to global climate change. Climate change regulation has gained momentum We may also be affected by competition for drilling rigs and the availability in recent years internationally and at the federal, regional, state and local of related equipment. Higher commodity prices generally increase the levels. On the international level, various nations have committed to reducing demand for drilling rigs, supplies, services, equipment and crews, and can their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto lead to shortages of, and increasing costs for, drilling equipment, services and Protocol was set to expire in 2012. In late 2011, an international climate personnel. Shortages of, or increasing costs for, experienced drilling crews and change conference in Durban, South Africa resulted in, among other things, equipment and services could restrict our ability to drill wells and conduct our an agreement to negotiate a new climate change regime by 2015 that operations. would aim to cover all major greenhouse gas emitters worldwide, including the U.S., and take effect by 2020. In November and December 2012, at an Health, safety and environmental matters international meeting held in Doha, Qatar, the Kyoto Protocol was extended General by amendment until 2020. In addition, the Durban agreement to develop Our operations are subject to various stringent and complex international, the protocol’s successor by 2015 and implement it by 2020 was reinforced. federal, state and local environmental, health and safety laws and regulations We are committed to controlling the emission of greenhouse gases and in the countries in which we operate. These laws and regulations govern implementing available technologies to reduce the impact caused by our matters including the emission and discharge of pollutants into the ground, operations. For example, during 2016 we began a migration plan to replace air or water; the generation, storage, handling, use and transportation of diesel with natural gas and electric generation. 98 GeoPark 20F Our HSE Management System purpose of conducting business outside Bermuda from a principal place Our health, safety and environmental management plan is focused on of business in Bermuda. As exempted companies, we and our Bermuda undertaking realistic and practical programs based on recognized world subsidiaries may not, without a license or consent granted by the Minister of practices. Our emphasis is on building key principles and company-wide Finance of Bermuda, participate in certain business transactions, including ownership and then expanding programs as we continue growing. Our transactions involving Bermuda landholding rights and the carrying on of S.P.E.E.D. philosophy and our HSE Plan have been developed with reference to business of any kind for which we or our Bermuda subsidiaries are not licensed ISO 14001 for environmental management issues, ISO 45000 for occupational in Bermuda. health and safety management issues, SA 8000 for social accountability and workers’ rights issues and applicable World Bank Standards. Insurance Our Environmental Policy We maintain insurance coverage of types and amounts that we believe to be customary and reasonable for companies of our size and with similar Our policy looks forward to meet or exceed environmental regulations operations in the oil and gas industry. However, as is customary in the in the countries in which we operate. We believe that oil and gas can be industry, we do not insure fully against all risks associated with our business, produced in an environmentally-responsible manner with proper care, either because such insurance is not available or because premium costs are understanding and management. Within our S.P.E.E.D. philosophy we considered prohibitive. have a team that is exclusively focused on securing the environmental authorizations and permits for the projects we undertake. This professional Currently, our insurance program includes, among other things, construction, and trained team, specialized in environmental issues, is also responsible fire, vehicle, technical, umbrella liability, director’s and officer’s liability and for the achievement of the environmental standards set by our Board employer’s liability coverage. Our insurance includes various limits and of Directors and for training and supporting our personnel. Our senior deductibles or retentions, which must be met prior to or in conjunction with executives, personnel in the field, visitors and contractors have also received recovery. A loss not fully covered by insurance could have a materially adverse training in proper environmental management. effect on our business, financial condition and results of operations. See “Item Our Health and Safety Policy 3. Key Information—D. Risk factors—Risks relating to our business—Oil and gas operations contain a high degree of risk and we may not be fully insured We continue looking for the best tools to manage our health and safety against all risks we face in our business.” policy. In 2018 we started the implementation of our program called SOS (Safety Operational Standards) that contributes to building better practices Industry and regulatory framework to control and minimize risks in our daily operations. Since 2016 we have also Colombia implemented the Proactive Observation Program, HSE training, work permits, Regulation of the oil and gas industry internal audits, drills, pre-job meetings and job safety analysis, among others. The ANH is responsible for managing all exploration lands not subject to previously existing association contracts with Ecopetrol. The ANH began As of December 31, 2018, on the last 12-month basis, our HSE development offering all undeveloped and unlicensed exploration areas in the country statistics workforce shows that Lost Time Injury Frequency (LTIF) was 0.42 (out under E&P Contracts and Technical Evaluation Agreements, or TEAs, which of every 1,000,000 worked hours), our Total Recordable Incident Rate (TRIR) resulted in a significant increase in Colombian exploration activity and was 1.25 (out of every 1,000,000 worked hours) and we had no fatal incidents competition, according to the ANH. The ANH is also in charge of negotiating related to operations in 2018. and executing contracts through “direct negotiation” mechanisms with In 2016, we subscribed to the International Association of Oil and Gas attention to special conditions in the areas to be explored, however the Producers in order to align our Management System and policies with the ANH has not issued the regulation for such direct granting of contracts. The best international standards. Certain Bermuda law considerations regulatory landscape in Colombia has recently changed. The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. Accord 008 of 2004 issued by the Directive Council of the ANH, as As a Bermuda exempted company, we and our Bermuda subsidiaries are repealed and replaced by Accord 004 of 2012, sets forth the necessary steps subject to regulation in Bermuda. We have been designated by the BMA as a for entering into E&P Contracts with the ANH. This Agreement regulates E&P non-resident for Bermuda exchange control purposes. This designation allows contracts entered into from May 4, 2012. E&P contracts entered into before us to engage in transactions in currencies other than the Bermuda dollar, that date are still regulated by Agreement 008 of 2004. Due to the oil price and there are no restrictions on our ability to transfer funds (other than funds crisis of 2015, the ANH implemented transitory measures through Agreements denominated in Bermuda dollars) in and out of Bermuda. 002, 003, 004 and 005 of 2015. On May 18, 2017, the ANH issued Agreement Under Bermuda’s law, “exempted” companies are companies formed for the measures adopted in 2014 and 2015. Agreement 002 of 2017 established 002, which repealed and replaced Agreement 004 of 2012 and transitory GeoPark 99 rules for the allocation of hydrocarbon areas and adopted criteria for the Pursuant to Colombian law, companies are obligated to pay royalties (a exploration and exploitation of hydrocarbons owned by Colombia, including percentage of their production) to the ANH in kind or in money as per ANH’s the selection of contractors, and management, execution, termination, instruction and pursuant to the E&P Contracts, companies must pay ANH an liquidation, monitoring, control and supervision of corresponding contracts. economic right called participating interest in the production, among other Agreement 002 of 2017 regulates contracts entered into from May 18, economic rights established in the E&P Contracts (i.e. high price provision, 2017. E&P contracts entered into before that date are still regulated by the technology transfer, use of the subsurface). Producing fields pay royalties in Agreements under which they were executed. accordance with the applicable law at the time of the discovery. Regulatory framework Additionally, in February 2019 the ANH published the Terms of Reference for Regulation of exploration and production activities the Permanent Competitive Bidding Process in which initially 20 blocks will be Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon offered to interested qualified bidders. resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or Taxation production of any hydrocarbon reserves. The Ministry of Mines and Energy is The Tax Statute and Law 9 of 1991 provide the primary features of the oil and the authority responsible for regulating all activities related to the exploration gas industry’s tax and exchange system in Colombia. Generally, national taxes and production of hydrocarbons in Colombia. under the general tax statute apply to all taxpayers, regardless of industry. The main taxes currently in effect—after the December 2016 tax reform discussed Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, below—are the income tax (40% for 2017, 37% for 2018 and 33% for 2019 establishes the general procedures and requirements that must be completed onwards), sales or value added tax (19%), and the tax on financial transaction by a private investor and disclosure procedures that need to be followed (0.4%). Additional regional taxes also apply. Colombia has entered into a during the performance of these activities. number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax. Exploration and production activities were governed by Decree 1895 of 1973 Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international until September 2009. Decree Law 2310 of 1974 (as complemented by Decree investment regime, regulates foreign capital investment in Colombia. 743 of 1975) governed the contracts and contracting processes carried out by Resolution 8 of the board of the Colombian Central Bank, or the Exchange Ecopetrol and the rules applicable to such contracts, and also provided that Statute, and its amendments contain provisions governing exchange Ecopetrol was responsible for administering the hydrocarbons resources in the operations. Articles 48 to 52 of Resolution 8 provide for a special exchange Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, but regime for the oil industry that removes the obligation of repayment to the all agreements entered into by us prior to 2003 with other oil companies are foreign exchange market currency from foreign currency sales made by still regulated by Decree 2310 of 1974. foreign oil companies. Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the Resolution 18-1495 of 2009, modified by Resolution 40048 of 2015, establishes foreign exchange market the capital required in order to meet expenses in a series of regulations regarding hydrocarbon exploration and exploitation. Colombian legal currency. Companies can avoid participating in this special In the E&P Contracts, operators are afforded access to blocks by committing oil and gas exchange regime, however, by informing the Colombian Central to an exploration work program. These E&P Contracts provide companies Bank, in which case they will be subject to the general exchange regime of with 100% of new production, less the participation of the ANH, which Resolution 8 and may not be able to access the special exchange regime for a participation may differ for each E&P Contract and depends on the percentage period of 10 years. that each company has offered to the ANH in order to be granted with a block, subject to an initial royalty payment of 8% and the payment of income taxes In December 2018, a new tax reform was enacted in Colombia. The legislation of 33%. In addition, the Colombian government also introduced TEAs, in which included significant changes in certain corporate income tax, statutory income companies that enter into TEAs are the only ones to have the right to explore, tax and legal provisions. This tax reform became effective on January 1, 2019. evaluate and select desirable exploration areas by executing seismic and /or drilling stratigraphic wells and to propose work commitments on those areas, The legislation included the progressive reduction of the general corporate and have a preemptive right to enter into an E&P Contract, thereby providing income tax rate, previously set at 40% for 2017 and 37% for 2018, as follows: companies with low-cost access to larger areas for preliminary evaluation prior to committing to broader exploration programs. A preemptive right is granted 33% in 2019, 32% in 2020, 31% in 2021 and 30% in 2022 and onwards. to convert the TEA into an E&P Contract. Exploration activities can only be Other changes that affect the Group are the following: carried out by the TEA contractor. • The withholding tax rate on dividends for non-resident shareholders was increased from 5% to 7.5%. 100 GeoPark 20F • The withholding tax rates were increased from 15% to 20% for payments 1986 of the Ministry of Mines, which set forth the revised text of the Decree to non-residents, related to consultancies, technical services, technical Law 1089 of 1975, on CEOPS. However, the right to explore and develop assistance, software and interest on loans of less than one year (for loans with fields is granted for each area under a CEOP between Chile and the relevant more than a year of maturity, the 15% rate remained unchanged). contractors. The CEOP establishes the legal framework for hydrocarbon • The withholding tax rate for payments to entities resident in non-cooperative activities, including, among other things, minimum investment commitments, countries, with no or low taxation, or subject to a preferential tax regime, was exploration and exploitation phase durations, compensation for the private increased from 15% to the corporate income tax rate (33 % for 2019, 32% for company (either in cash or in kind) and the applicable tax regime. Accordingly, 2020, 31% for 2021 and 30% for 2022 and onwards). all the provisions governing the exploitation and development of our Chilean • The deduction of interest attributed to a permanent establishment in operations are contained in our CEOPs and the CEOPs constitute all the Colombia by its head office was limited to when they have been subject to licenses that we need in order to own, operate, import and export any of withholding tax. the equipment used in our business and to conduct our gas and petroleum • Regarding undercapitalization, the debt limit which interests can be operations in Chile. deducted, for income tax purposes, was reduced to two times the net equity of the taxpayer as of December 31 of the previous year. Under Chilean law, the surface landowners have no property rights over • Transfers of participations in foreign entities that represent indirect disposals the minerals found under the surface of their land. Subsurface rights do not of assets in Colombia are subject to income tax or occasional earnings tax. generate any surface rights, except the right to impose legal easements or • VAT paid for acquisition of productive fixed assets can be discounted from rights of way. Easements or rights of way can be individually negotiated with the taxpayer’s income tax individual surface land owners or can be granted without the consent of the landowner through judicial process. Pursuant to the Chilean Code of Mines, a An audit benefit was granted by the reform, establishing that tax returns for judge can permit a party to use an easement pending final adjudication and the 2019 and 2020 fiscal years showing a net income tax 30% or 20% higher, settlement of compensation for the affected landowner. respectively, than the one declared in the previous year would be considered definitive 6 months or 12 months after they became due, also respectively, if Taxation there were no objections or requests from the tax authority. With regard to indirect taxes on hydrocarbon exploitation, the general rule is Chile Regulation of the oil and gas industry that hydrocarbons are transferred to the contractor (its retribution under the CEOP), and those re-acquisitions from the contractor performed by Chile or its enterprises, as well as their corresponding acts, contracts and documents, Under the Chilean Constitution, the state is the exclusive owner of all mineral are tax exempt. In addition, hydrocarbon exports by the contractor are also and fossil substances, including hydrocarbons, regardless of who owns the tax exempt. With regard to income taxes, as provided by article 5 of Decree land on which the reserves are located. The exploration and exploitation Law No. 1,089, the contractor is subject either to a single tax calculated on of hydrocarbons may be carried out by the state, companies owned by the its retribution, equal to 50% of such retribution, or to the general income tax state or private entities through administrative concessions granted by the regime established in the Income Tax Law (Decree Law No. 824 of 1974), in President of Chile by Supreme Decree or CEOPs executed by the Minister of force at the time of the execution of the public deed which contains CEOPs, Energy. Exploitation rights granted to private companies are subject to special terms of which will be applicable and invariable throughout the duration of taxes and/or royalty payments. The hydrocarbon exploration and exploitation the contract. Income in Chile is subject to corporate tax on an accrual basis and industry is supervised by the Chilean Ministry of Energy. has a current rate of 25.5% for fiscal year 2017. The applicable and invariable corporate income tax rates of our CEOPs range between 15% and 18.5%, as In Chile, a participant is granted rights to explore and exploit certain assets follows: the Fell Block is subject to a rate of 15%, the Tranquilo Block is subject to under a CEOP. If a participant breaches certain obligations under a CEOP, the a rate of 17% and the Flamenco, Isla Norte and Campanario Blocks are subject participant may lose the right to exploit certain areas or may be required to a rate of 18.5% for the income accrued or received during 2012 and 17% for to return all or a portion of the awarded areas to Chile with no right of the income accrued or received during 2013 and onward. Dividends or profits compensation. Although the government of Chile cannot unilaterally modify distributed to the foreign shareholders of the contractors are subject to 35% the rights granted in the CEOP once it is signed, exploration and exploitation are Additional Withholding Tax with a tax credit for the corporate income tax paid nonetheless subject to significant government regulations, such as regulations by the contractor. With regard to the value added tax, contractors may obtain concerning the environment, tort liability, health and safety and labor. as a refund the value added tax (which is 19% according to the Sales and Regulatory framework Services Tax Law contained in Decree Law No. 825 of 1974) supported or paid Regulation of exploration and production activities on the import or purchase of goods or services used in connection with the Oil and gas exploration and development is governed by the Political exploration and exploitation activities. The applicable tax regime for each CEOP Constitution of the Republic of Chile and Decree with Law Force No 2 of remains unchanged throughout the duration of the CEOP. GeoPark 101 The Chilean Congress approved a reform to the income tax law in September Taxation 2014 which was amended in February 2016. Under this reform the income tax The Brazilian Petroleum Law introduced significant modifications and benefits rate will increase from 20% in 2013 to: 21% in 2014, 22.5% in 2015, 24% in 2016, to the taxation of oil and natural gas activities. The main component of 25.5% in 2017 and 27% in 2018. The operating subsidiaries that we control in petroleum taxation is the government take, comprised of license fees, fees Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes payable in connection with the occupation or title of areas, royalties and a Limitada, are not affected by the income tax reform mentioned since they are special participation fee. The introduction of the Brazilian Petroleum Law covered by the tax treatment established in the CEOPs. The above has been presents certain tax benefits primarily with respect to indirect taxes. Such confirmed by the Chilean IRS through ruling N°2478/2016. indirect taxes are very complex and can add significantly to project costs. Direct taxes are mainly corporate income tax and social contribution on net profit. Brazil Regulation of the oil and gas industry With the effectiveness of the Brazilian Petroleum Law and the regulations Article 177 of the Brazilian Federal Constitution of 1988 provides for the promulgated by the ANP, concessionaires are required to pay the Brazilian Federal Government’s monopoly over the prospecting and exploration of oil, federal government the following: natural gas resources and other fluid hydrocarbon deposits, as well as over • license fees; the refining, importation, exportation and sea or pipeline transportation of • rent for the occupation or retention of areas; crude oil and natural gas. Initially, paragraph one of article 177 barred the • special participation fee; and assignment or concession of any kind of involvement in the exploration • royalties on production. of oil or natural gas deposits to private industry. On November 9, 1995, however, Constitutional Amendment Number 9 altered paragraph one of The minimum value of the license fees is established in the bidding rules for article 177 so as to allow private or state-owned companies to engage in the the concessions, and the amount is based on the assessment of the potential, exploration and production of oil and natural gas, subject to the conditions as conducted by the ANP. The license fees must be paid upon the execution to be set forth by legislation. Regulatory framework Pricing policy of the concession contract. Additionally, concessionaires are required to pay a rental fee to landowners varying from 0.5% to 1.0% of the respective hydrocarbon production. Until the enactment of the Brazilian Petroleum Law, the Brazilian government The special participation fee is an extraordinary charge that concessionaires regulated all aspects of the pricing of oil and oil products in Brazil, from the must pay in the event of obtaining high production volumes and/or cost of oil imported for use in refineries to the price of refined oil products profitability from oil fields, according to criteria established by applicable charged to the consumer. Under the rules adopted following the Brazilian regulation, and is payable on a quarterly basis for each field from the date on Petroleum Law, the Brazilian government changed its price regulation policies. which extraordinary production occurs. This participation rate, whenever due, Under these regulations, the Brazilian government: (1) introduced a new may reach up to 40% of net revenues depending on (i) volume of production methodology for determining the price of oil products designed to track and (ii) whether the block is onshore, shallow water or deep water. Under the prevailing international prices denominated in U.S. dollars, and (2) gradually Brazilian Petroleum Law and applicable regulations issued by the ANP, the eliminated controls on wholesale prices. Concessions special participation fee is calculated based upon quarterly net revenues of each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate In addition to opening the Brazilian oil and natural gas industry to private for the period) less: royalties paid; investment in exploration; operational costs; investment, the Brazilian Petroleum Law created new institutions, including and depreciation adjustments and applicable taxes. the ANP, to regulate and control activities in the sector. As part of this mandate, the ANP is responsible for licensing concession rights for the The ANP is responsible for determining monthly minimum prices for exploration, development and production of oil and natural gas in Brazil’s petroleum produced in concessions for purposes of royalties payable with sedimentary basins through a transparent and competitive bidding process. respect to production. Royalties generally correspond to a percentage The ANP has conducted 14 bidding rounds for exploration concessions ranging between 5% and 10% applied to reference prices for oil or natural from 1999 through 2017. Our PN-T-597 is still subject to the entry into the gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. See “—Our operations—Operations in Brazil” and concession agreement. In determining the percentage of royalties applicable “Item 3. Key information—D. Risk factors—Risks relating to our business—The to a particular concession, the ANP takes into consideration, among other PN-T-597 concession is subject to an injunction and may not close” for more factors, the geological risks involved and the production levels expected. information. 102 GeoPark 20F State VAT (ICMS) taxation, the amount of the tax cannot be considered as a credit (even though ICMS is a state sales tax. This tax is due on the local sale of oil and gas, based IPI is under the non-cumulative regime applicable for IPI’s taxpayers), which on the sale price, including the ICMS itself. means that this will be a cost for the legal entity acquirer. In relation to the For intrastate transactions (carried out by a seller and a buyer located in the be obliged to pay the IPI due on the transaction. For the same aforementioned same Brazilian state) or imports, the ICMS rate is determined by the legislation reasons for the O&G companies (upstream), this will be considered as cost importation, the importer of record will be considered as the taxpayer and will of the state where the sale is made and generally varies from 17% to 20%. when the importation is subject to IPI. Interstate transactions (carried out between a seller and buyer located in different Brazilian states), in turn, are subject to reduced rates of 4% (if the ISS is a cumulative tax which is due on provided services and imported products are imported and not submitted to a manufacturing process or, services. Usually, regarding local transactions, such tax is included in the price in case of further manufacturing, if the resulting product has a minimum of the service charged by the service provider. In relation to the import of imported content of 40%), 7% or 12%, depending on the states involved. One service, the Brazilian entity contractor is responsible for the payment of the exception is that, due to the immunity established by the Brazilian Federal ISS, which means that, depending on contractual arrangement, the tax burden Constitution, ICMS is not due on interstate crude oil transactions when may be supported by the Brazilian contractor or the foreign service provider. destined to industrialization and commercialization. On the other hand, in case of consumables or fixed assets, the buyer must pay to the state where the ISS tax rate may vary from 2% to 5% and will depend on the nature of service, buyer is located, the ICMS DIFAL, which is calculated based on the difference as well as where the service provider is located (in general, some exceptions between the interstate rate and the buyer’s own internal ICMS rate. may apply). ICMS is calculated under the noncumulative regime, and therefore some input Additionally, GeoPark Brazil was granted in 2018 a tax benefit issued by transactions could result in tax credits (for example the acquisition of inputs SUDENE (Northeastern Development Superintendence), by means of the and fixed assets directly used in the company’s activity). Constitutive Act No. 0069/2018, which approved the tax incentive to reduce by Social contribution taxes on gross revenue (PIS and COFINS) profits, based on Article 1 of the Provisory Measure 2,199-14 of August 24, PIS and COFINS are social contribution taxes charged on gross revenues 2001, in accordance with the requirements established by the Decree 6,539 of earned by a Brazilian Federal Revenue noncumulative regime of calculation. August 18, 2008. 75% the Income Tax and Additions, calculated over the company exploration Under the noncumulative regime, PIS and COFINS are generally charged at The benefit will be valid for 10 years, starting from January 1, 2018, under a combined nominal rate of 9.25% (1.65% PIS and 7.6% COFINS) on national the condition of modernizing the entire project on the SUDENE operating revenues earned by a legal entity. In that case, certain business costs result area, observing all provided legal conditions and requirements that includes in tax credits to offset PIS and COFINS liabilities (e.g., input and services compliance with labor and social law and with all environmental protection acquisitions, expenses of depreciation and amortization of machinery, and control regulations, annual submission of a declaration of income and a equipment and other fixed assets acquired to be directly used in the restriction to the distribution to partners or shareholders of the tax amount company’s activities). PIS and COFINS paid upon the importation of certain which is not payed due to the tax exemption. inputs, assets and services contracted that are destined to the company’s activity are also creditable. Although upstream industries are generally subject The noncompliance with the requirements provided constitutes a default of to this regime, it is not clear yet when this benefit is applied according to the the beneficiary company in respect to SUDENE and shall be subject to the stage of the field, (exploration or production). applicable penalties. Peru Since July 1, 2015, taxpayers subject to the noncumulative regime must Regulation of the oil and gas industry calculate PIS and COFINS over certain financial revenues, applying rates of The hydrocarbons activities in Peru are mainly regulated by the General 0.65% and 4%, respectively. Hydrocarbons Law (Law 26,221), and several regulations enacted in order to develop the provisions included in such law. Federal Industrialization VAT (IPI) and Municipality VAT (ISS) IPI is a non-cumulative tax and may be due on goods acquisitions by According to the Hydrocarbons Law, oil and gas exploration and production importation or national transactions. The IPI rate will be applied depending activities are carried out under license or service contracts granted by the on the NCM classification of the product according to TIPI (Table of IPI). On government. Under a license contract, the investor pays a royalty, whereas the acquisition of local goods subject to IPI, such tax is included in the price under a service contract, the government pays remuneration to the contractor. of the good. Considering that O&G activity (upstream) is not subject to IPI As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons, GeoPark 103 a license contract does not imply a transfer or lease of property over the in Peru and to promote exploration; as well as defining what will be the area of exploration or exploitation. By virtue of the license contract, the treatment on VAT in hydrocarbon exploration projects). At the end of 2018, contractor acquires the authorization to explore or to exploit hydrocarbons the Congress approved to extend the VAT refund to this type of projects to in a determined area, and Perupetro (the entity that holds the Peruvian state December 2019. interest) transfers the property right in the extracted hydrocarbons to the contractor, who must pay a royalty to the state. The stabilized income tax regime will only cover the activities of the License Regulatory framework Agreement (exploration and/or exploitation activities), therefore, the related activities (i.e., activities related to oil and gas, but not carried out under the License and service contracts are approved by a supreme decree issued by terms of the contract) and other activities (i.e., activities not related to oil and the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of gas) will be governed by the income tax rules in force to date. Energy and Mining, and can only be modified by a written agreement signed by the parties. Before initiating any negotiation, every oil and gas company Resident companies (incorporated in Peru), are subject to income tax on must be duly qualified by Perupetro, in order to determine if it fulfills all the their worldwide taxable income. Branches and permanent establishments of requirements needed to develop exploration and production activities under foreign companies that are located in Peru and non-resident entities are taxed the contract form requirements mentioned above. on Peruvian source income only. License and services agreements may be granted for just an exploitation With respect to the Morona Agreement, in which we take part, the applicable stage -when a commercial discovery has been made- or for an exploration income tax stabilized regime is from 1995, which is the year of subscription and exploitation stage –when such discovery has not been made yet. In this of the original License Agreement. The income tax rate in 1995 was 30% and case, the exploration phase will last no more than 7 years, counted from the there was no withholding income tax for dividends. Additionally, in 1995 effective date of the contract (60 days after the signing date). This term can it was stated that the income tax should not be lower than 2% of the net be divided into several periods as agreed in the contract, and all of them assets of the Company (the “Minimum Income Tax”). The Minimum Income with a minimum work obligation that should be fulfilled by a contractor in Tax was later declared unconstitutional, which is why, even when there was a order to access the next exploration period. The exploration phase will last tax stability contract, the Minimum Income Tax has been understood as not until a declaration of commercial discovery is made by the contractor. The applicable or enforceable. exploitation phase will last from the date of such declaration until 30 years from the date of the contract. Taxable income is generally computed by reducing gross revenue by cost of goods sold and all expenses necessary to produce the income or maintain The Ministry of Energy and Mines may exceptionally authorize an extension the source of income. Certain types of revenue, however, must be computed of three years for the exploration stage, if the contractor has fulfilled with the as specified in the tax law and some expenses are not fully deductible for minimum work program established in the contract, and also commits to fulfill tax purposes. Business transactions must be recorded in legally authorized an additional work program that justifies such extension. The contractor shall accounting records that are in full compliance with the International be responsible for providing the technical and economic resources required Accounting Standards (IAS). Contractors in a license or services contract for for the execution of the operations of this phase. the exploration or exploitation of hydrocarbons (Peruvian corporations and branches) are entitled to keep their accounting records in foreign currency, The Peruvian regulations also established the roles of the Peruvian but taxes must be paid in Peruvian Soles (“PEN”). government agencies that regulate, promote and supervise the oil and gas industry, including the Ministry of Energy and Mines, Perupetro and Any investments in a contract area that did not reach the commercial OSINERGMIN. Taxation extraction stage and that were totally released, can be accumulated with the same type of investments made in another contract area that has reached the The fiscal regime that applies in Peru to the oil and gas industry consists of a stage of commercial extraction. combination of corporate income tax, royalties and other levies. In general terms, oil and gas companies are subject to the general corporate chosen by the contractor. If the contractor has entered into a single contract, income tax regime that is stabilized in the applicable regime on the date of the accumulated investments are charged as a loss against the results of the subscription of the original License Agreement (due to a tax stability contract); contract for the year of total release of the area for any contract that did not nevertheless, there are certain special tax provisions for the oil and gas sector reach the commercial extraction stage, with the exception of investments (the approval of the new Organic Hydrocarbons Law is pending in order to consisting of buildings, power installations, camps, means of communication, encourage investments in license agreements that are already operating equipment and other goods that the contractor keeps or recovers to use in the These investments are amortized in accordance with the amortization method 104 GeoPark 20F same operations or in other operations of a different nature. (ii) the “cost+expense+mark up” structure to deduct the expenses for services The contractor determines the tax base and the amount of the tax, separately between related parties will now only be applicable to low added value and for each contract. If the contractor carries out related activities or other services, and not to entirety of services between related parties. activities, the contractor is obligated to determine the tax base and the amount of tax, separately, and for each activity. The corresponding tax is • Legislative Decree 1381 updates the concept of tax havens to include “non- determined based on the income tax provisions that apply in each case cooperative” countries or countries that have a “preferential regime”. The law (subject to the tax stability provisions for contract activities and based on the has established a criterion to qualify a country under this concept. regular regime for the related activities or other activities). The total income tax amount that the contractor must pay is the sum of the amounts calculated In addition, when applying the Comparable Uncontrolled Price (CUP) method for each contract, for both the related activities and for the other activities. to cross-border transactions involving commodities, the Legislative Decree The forms to be used for tax statements and payments are determined by the establishes that the arm’s-length price for Peruvian income tax purposes tax administration. If the contractor has more than one contract, it may offset must be determined by reference to a publicly quoted price. The actual the tax losses generated by one or more contracts against the profits resulting pricing date or period of pricing dates should be used as a reference to from other contracts or related activities. Moreover, the tax losses resulting determine the price for the transaction, as long as independent parties in from related activities may be offset against the profits from one or more comparable circumstances would have relied upon the same pricing date. contracts. The taxpayer needs to notify the SUNAT (i.e., Peruvian Tax Authority) of the actual pricing date or period of pricing dates used to determine the price for It is possible to choose the allocation of tax losses to one or more of the the transaction. contracts or related activities that have generated the profits, provided that the losses are depleted or compensated to the limit of the profits available. Legislative Decree 1424 extends the application of sub capitalization rules This means that if there is another contract or related activity, the taxpayer (maximum deductible interest determination) to unrelated parties. can continue compensating tax losses until they are completely offset. A contractor with tax losses from one or more contracts or related activities may Likewise, as of 2021, the interest generated in transactions with related or not offset them against profits generated by the other activities. Furthermore, unrelated parties that exceeds 30% of EBITDA of the preceding year will not in no case may tax losses generated by the other activities be offset against be deductible. Interest that is not deducted may be carried forward for up to the profits resulting from the contracts or the related activities. four years. During the exploration phase, operators are exempt from import duties and On the other hand, this Legislative Decree introduces in the Income Tax Law other forms of taxation applicable to goods intended for exploration activities. scenarios in which Permanent Establishments are triggered. Exemptions are withdrawn at the production phase, but exceptions are made in certain instances, and the operator may be entitled to temporarily import Additionally, other provisions have been included in this Legislative Decree, goods tax-free for a two-year period (“Temporary Import”). A temporary for instance, that an indirect transfer of Peruvian shares will always be Import may be extended for additional one year periods for up to two times triggered if the amount paid for the shares of a non-resident entity that upon the request of an operator, approval of the Ministry of Energy and corresponds to the Peruvian shares is equivalent to or higher than 40,000 Tax Mines and authorization of the Superintendencia Nacional de Aduanas y de Units (approximately US$ 50.3 million). Administracion Tributaria (Peruvian Customs Agency). • Legislative Decree 1425 establishes a general and specific rules to determine Several Legislative Decrees were published on September 13, 2018, when to consider income or expenses as “accrued”. introducing modifications to the Income Tax Law and the Tax Code. Tax Code: Income Tax Law: These dispositions are effective since January 1, 2019. • Legislative Decree 1422 includes provisions for the implementation of the • Legislative Decree 1369 allows companies to deduct the payment for technical General Anti-Avoidance Rule (GAAR) and will be applicable to facts, acts and assistance, assignment in use and other services provided by non-domiciled situations from July 19, 2012 onwards and even to tax audits already started. in the fiscal year that the service is paid, as long as the payment be made before the deadline for submitting the corresponding Income Tax Affidavit. In case of entities with a Board of Directors, that Board of Directors will be Additionally, new transfer pricing rules were established: (i) the obligations to cannot be delegated. The Board of Directors must evaluate the tax planning apply the benefit test is now only applicable to operations between related strategies implemented up to September 14, 2018 in order to ratify or modify parties and no longer to operations with, towards or through tax havens; and them. The term for ratify or modify them will end on March 29, 2019. responsible of approving the tax planning of the entity. That obligation GeoPark 105 • Legislative Decree 1372 establishes the obligation for legal entities resident Deregulation Decrees eliminated restrictions on imports and exports of crude in Peru to identify, obtain, update, report on the identification of their final oil, deregulated the domestic oil industry, and effective January 1, 1991, the beneficiaries, maintain that information and present a declaration to the Tax prices of oil and petroleum products were also deregulated. In 1992, Law Authority that provides the information that includes the chain of ownership No. 24,145, referred to as the Privatization Law, privatized YPF and provided or control, the percentage ownership, among others. This Legislative Decree for transfer of hydrocarbon reservoirs from the Argentine government to the is effective since August 03, 2018, and the Resolution that establishes the provinces, subject to the existing rights of the holders of exploration permits deadlines for submitting the informative affidavit of final beneficiary is still and production concessions. pending. In May 2018, GeoPark Perú SAC applied for a VAT anticipated refund regime new state-owned energy company, Energía Argentina S.A. (“ENARSA”). The that will allow it to recover the tax paid until the first oil is produced. The corporate purpose of ENARSA was initially the exploration and exploitation of regime is established by Legislative Decree 973, which demands a minimum solid, liquid and gaseous hydrocarbons; the transport, storage, distribution, investment of US$5.0 million, and a preoperative period of 2 years (which for commercialization and industrialization of these products; as well as Morona Block starts on December 2016). the transportation and distribution of natural gas, and the generation, In October 2004, the Argentine Congress enacted Law No. 25,943, creating a Environmental Regulation transportation, distribution and sale of electricity. Moreover, Law No. 25,943 granted ENARSA all offshore areas located beyond 12 nautical miles from the Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling coastline up to the outer boundary of the continental shelf that were vacant of exploration wells, etc.) the contractor must file and obtain an approval for at the time of the effectiveness of this law (i.e. November 3, 2004). In 2014, an Environmental Impact Study (EIS), which is the most important permit all open acreage offshore exploration permits and exploitation concessions related to HSE for any hydrocarbon project. This study includes technical, were conveyed to the National Energy Secretary (NSE) and all existing JV environmental and social evaluations of the project to be executed in order agreements entered into by ENARSA with private investors were conveyed to define the activities that should be required for preventing, minimizing, by ENARSA to YPF in accordance with Section 30, New Hydrocarbons Act No. mitigating and remediation of the possible negative environmental and social 27,007. impacts that the hydrocarbon project may generate. There are general environmental regulations for the protection of water, soils, Act. This law declared achieving self-sufficiency in the supply of hydrocarbons, air, endangered species, biodiversity, natural protected areas, etc. In addition, as well as in the exploitation, industrialization, transportation and sale of there are specific environmental regulations applicable to the hydrocarbon hydrocarbons, a national public interest and a priority for Argentina. In On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty industry. Argentina addition, the law expropriated 51% of the share capital of YPF, the largest Argentine oil company, from Repsol, the largest Spanish oil company. Regulatory framework On July 28, 2012, Presidential Decree 1277/2012, which regulated the From the 1920s to 1989, the Argentine public sector dominated the upstream Hydrocarbon Sovereignty Law, was released, creating a Strategic Planning and segment of the Argentine oil and gas industry and the midstream and Coordination Committee for the National Hydrocarbon Investment Plan and downstream segment of the business. vesting it with the power to set the sector’s reference prices and to develop investment plans for the country to increase production and reserves. The The Hydrocarbon Law No. 17,319 enacted in 1967 continues in force until decree introduced important changes to the rules governing Argentina’s today, subject to amendments introduced by the Deregulation Decrees and oil and gas industry, including the repeal of certain articles of Deregulation Laws No. 24,145, 26,197 and 27,007. Decrees passed during 1989 relating to free marketability of hydrocarbons The Hydrocarbon Law No. 17,319 provided for the existence of a state-owned at negotiated prices, the deregulation of the oil and gas industry, freedom to oil & gas company (originally, YPF) for whom private companies served import and export hydrocarbons and the ability to keep proceeds from export as service contractors or joint venture partners. But it also provided for a sales in foreign bank accounts. concession & royalty system which in practice was not used until after the YPF privatization. On January 4, 2016, immediately after the new national administration took office, Presidential Decree 272/2015 was released. This Decree abrogated In 1989, Argentina enacted certain laws aimed at privatizing the majority the provisions of the Presidential Decree 1277/2012 which had repealed the of its state-owned companies and issued a series of presidential decrees Deregulation Decrees. Thus, the Deregulation Decrees were reinstated. (namely, Decrees No. 1055/89, 1212/89 and 1589/89 (the “Oil Deregulation Decrees”), relating specifically to deregulation of energy activities). The Oil Other measures have also been taken by the new presidential administration 106 GeoPark 20F aimed at reducing government intervention and reestablishing market forces • With regards to concessions, three types of concessions are provided, namely, in the oil & gas industry: conventional exploitation, unconventional exploitation, and exploitation in • Effective October 1 2017 both domestic oil prices at the wellhead and the continental shelf and territorial waters, establishing the respective terms gasoline prices at the dispenser were allowed to float freely, ending floor for each type. pricing schemes sheltering the oil producers during low oil times. • The terms for hydrocarbon transportation concessions were adjusted in order • Also, effective October 22, 2018, Resolution 103/2018 established a new to comply with the exploitation concessions terms. framework governing natural gas export authorization proceedings, • With regards to royalties, a maximum of 12% is established, which may reach including long term and short-term firm export authorizations, interruptible 18% in the case of granted extensions, where the law also establishes the export authorizations, summer export authorizations and operational payment of an extension bond for a maximum amount equal to the amount exchanges. These new natural gas exports were soon put in practice and resulting from multiplying the remaining proven reserves at the end of natural gas exports by pipeline to neighbouring countries resumed in 2018. effective term of the concession by 2% of the average basin price applicable to the respective hydrocarbons over the 2 years preceding the time on which Domain and Jurisdiction of hydrocarbons resources the extension was granted. After a constitutional reform enacted in 1994, eminent domain over • The extension of the Investment Promotion Regime for the Exploitation of hydrocarbon resources lying in the territory of a provincial state is now vested Hydrocarbons (Decree No. 929/2013) is established for projects representing in such provincial state, while eminent domain over hydrocarbon resources a direct investment in foreign currency of at least 250 million dollars, lying offshore on the continental platform beyond the jurisdiction of the increasing the benefits for other type of projects. coastal provincial states is vested in the federal state. Regulation of transportation activities Thus, oil and gas exploration permits and exploitation concessions are now Exploitation concessionaires have the exclusive right to obtain a granted by each provincial government. A majority of the existing concessions transportation concession for the transport of oil and gas from the provincial were granted by the federal government prior to the enactment of Law states or the federal government, depending on the applicable jurisdiction. No.26,197 and were thereafter transferred to the provincial states. Such transportation concessions include storage, ports, pipelines and other Hydrocarbon Exports and Self Sufficiency fixed facilities necessary for the transportation of oil, gas and by-products. Transportation facilities with surplus capacity must transport third parties’ Achieving self-sufficiency has been an energy policy goal from the early days hydrocarbons on an open-access basis, for a fee which is the same for all users of the industry. on similar terms. As a result of the privatizations of YPF and Gas del Estado, a few common carriers of crude oil and natural gas were chartered and continue Section 6 of the Hydrocarbon Law No. 17,319 allows the National Executive to operate to date. Branch to authorize the export of hydrocarbons. At times when the domestic production of liquid hydrocarbons is insufficient to cover domestic needs, the Effective February 8, 2019, to promote transportation capacity expansions, delivery of the entire availability of such locally produced hydrocarbons to the Decree 115/2019 allowed interested shippers to reserve transportation domestic market shall be mandatory, with such exceptions as may be justified capacity in new or expanded pipelines through freely negotiated capacity on technical grounds. reservation agreements. In turn, Section 3 of the Natural Gas Regulatory Framework 24,076 allows the Taxation National Executive Branch to authorize the export of natural gas. The granting Exploitation concessionaires are subject to the general federal and provincial of natural gas export permits is regulated in detail. tax regime. The most relevant federal taxes are the income tax (30%), the value added tax (21%) and a tax on assets. The most relevant provincial taxes are the Supply privileges favouring the domestic market to the detriment of the turnover tax (3% on average) and stamp tax. export market, including hydrocarbon export restrictions, domestic price controls, export duties and domestic market supply obligations have been Tax reform was enacted in Argentina in December 2017. The legislation implemented several times. included significant changes to certain corporate income tax and statutory income tax provisions, including rate reductions. Most of the tax provisions Regulation of exploration and production activities were effective as of the beginning of fiscal year 2018. New Hydrocarbon Act: In October 31, 2014 the Argentine Republic Official Gazette published the text With this tax reform, the corporate income tax, which was previously 35% has of Law No. 27,007, amending the Hydrocarbon Law No. 17,319. The most relevant aspects of the new law are as follows: the following rate schedule:  • 30% in 2018 and 2019 GeoPark 107 Operating and financial review and prospects • 25% in 2020 and 2021 and onwards. Other changes include the following: Factors affecting our results of operations We describe below the year-to-year comparisons of our historical results and • New withholding tax on dividends—with the applicable rates for the analysis of our financial condition. Our future results could differ materially non-resident shareholders of: (1) 7% for dividends distributed out of the from our historical results due to a variety of factors, including the following: distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and (2) 13% for dividends distributed out of the distributing entity’s previously Discovery and exploitation of reserves taxed profits of fiscal years 2020 and onwards. Our results of operations depend on our level of success in finding, acquiring • Application of inflation adjustment for corporate tax purposes is reinstated (including through bidding rounds) or gaining access to oil and natural under certain circumstances (e.g. if the inflation cumulative rate for three gas reserves. While we have geological reports evaluating certain proved, consecutive years exceeds 100%). contingent and prospective resources in our blocks, there is no assurance that • Possible tax revaluation of investment in fixed assets, under payment of a we will continue to be successful in the exploration, appraisal, development special tax. and commercial production of oil and natural gas. The calculation of our • Certain restrictions for the deduction of exchange differences on income geological and petrophysical estimates is complex and imprecise, and it is tax. possible that our future exploration will not result in additional discoveries, • New export taxes applicable to services activities. and, even if we are able to successfully make such discoveries, there is no • Allow for short term recovery of VAT paid on acquisitions or imports of certainty that the discoveries will be commercially viable to produce. capital goods, when non-recoverable with VAT on usual sales. C. Organizational structure For the year ended December 31, 2018, we made total capital expenditures of US$ 124.7 million (US$97.0 million, US$7.9 million, US$9.0 million, US$8.5 We are an exempted company incorporated pursuant to the laws of Bermuda. million and US$2.3 million in Colombia, Chile, Argentina, Peru and Brazil, We operate and own our assets directly and indirectly through a number respectively), consisting of US$43.5 million related to exploration. of subsidiaries. See an illustration of our corporate structure in Note 21 (“Subsidiary undertakings”) to our Consolidated Financial Statements. Oil prices were volatile since the end of 2014. In preparation for continued During 2017, we decided to incorporate a subsidiary in the United Kingdom volatility, we have developed multiple scenarios for our 2019 capital (international investor centre) to conduct our businesses and financial expenditure program. See “Item 4. Information on the Company –B. Business decisions. Overview—2019 Strategy and Outlook.” D. Property, plant and equipment Funding for our capital expenditures relies in part on oil prices remaining close See “—B. Business Overview—Title to properties.” to our estimates or higher levels and other factors to generate sufficient cash ITEM 4A. UNRESOLVED STAFF COMMENTS and the covenants in our financing agreements, as well as the amount of cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity Not applicable. 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 ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS obtain from prepayment agreements such as the Trafigura Agreement, which A. Operating results is our offtake and prepayment agreement. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work The following discussion of our financial condition and results of operations program which would cause us to further decrease our work program, which should be read in conjunction with our Consolidated Financial Statements could harm our business outlook, investor confidence and our share price. and the notes thereto as well as the information presented under “Item 3. Key Information— A. Selected financial data.” If oil prices average higher than the base budget price, we have the ability to allocate additional capital to more projects and increase its work and The following discussion contains forward-looking statements that involve risks investment program and thereby further increase oil and gas production. and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including those Our results of operations will be adversely affected in the event that our set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking estimated oil and natural gas asset base does not result in additional reserves statements.” 108 GeoPark 20F that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our based on a formula that takes into account various international prices of anticipated reserves will continually decrease, which would have a material methanol, including US Gulf methanol spot barge prices, methanol spot adverse effect on our business, results of operations and financial condition. Rotterdam prices and spot prices in Asia. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—A substantial or extended decline Oil and gas revenue and international prices in oil, natural gas and methanol prices may materially adversely affect our Our revenues are derived from the sale of our oil and natural gas production, business, financial condition or results of operations.” as well as of condensate derived from the production of natural gas. The price realized for the oil we produce is generally linked to Brent or Vasconia. In Brazil, prices for gas produced in the Manati Field are based on a long-term The price realized for the natural gas we produce in Chile is linked to the off-take contract with Petrobras. The price of gas sold under this contract is international price of methanol, which is settled in the international markets denominated in reais and is adjusted annually for inflation pursuant to the in US$. The market price of these commodities is subject to significant Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the fluctuation and has historically fluctuated widely in response to relatively “IGPM”). See Note 3 to our Consolidated Financial Statements. minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. In Argentina, the realized oil prices for our production in the Neuquén Basin follows the “Medanito” blend oil price reference, which has traditionally been From January 1, 2014 to December 31, 2018, Brent spot prices ranged from a linked to ICE Brent adjusted by certain marketing and quality discounts based low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub natural on API, delivery point and transport costs. Between May and November gas average spot prices ranged from a low of US$1.7 per mmbtu to a high of 2018, Medanito crude prices were capped industry-wide between US$ 65 US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of per barrel and US$ 70 per barrel. Since December 2018, domestic prices have US$250.0 per metric ton to a high of US$635.1 per metric ton. Furthermore, reconnected to the international benchmark. oil, natural gas and methanol prices do not necessarily fluctuate in direct relationship to each other. Gas sales in Argentina are carried out through annual contracts that go from May to April. The price of the gas sold under these contracts depends mainly As a consequence of the oil price crisis which started in the second half of on domestic supply and demand and regulation affecting the sector. 2014 (WTI and Brent, the main international oil price benchmarks, fell more than 60% between October 2014 and February 2016), we took decisive steps If the market prices of oil and methanol had fallen by 10% as compared to in 2015 and 2016 to adapt to the new oil price environment. We reduced our actual prices during the year, with all other variables held constant, and taking capital expenditure program from US$238 million in 2014 to US$48 million in into account the impact of the derivative contracts in place, post-tax profit for 2015 and US$39 million in 2016 and implemented significant cost reduction the year ended December 31, 2018 would have been lower by US$13.7 million initiatives that resulted in production and operating costs being reduced by (post-tax loss would have been higher by US$10.4 million in 2017). 49% (2016 versus 2014), and administrative expenses being reduced by 26% (2016 versus 2014), while increasing average production to approximately 22.4 Production and operating costs mboepd and increasing our proved reserves to 73.6 mmboe. Our production and operating costs consist primarily of expenses associated In October 2016, we decided to manage part of our exposure to the volatile plant leasing, facilities and wells maintenance (including pulling works), crude oil price using derivatives. For further information related to Commodity labor costs, contractor and consultant fees, chemical analysis, royalties and Risk Management Contracts, please see Note 8 to our Consolidated Financial products, among others. As commodity prices increase or decrease, our Statements. production costs may vary. We have historically not hedged our costs to with the production of oil and gas, the most significant of which are gas protect against fluctuations. Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the price of oil we sell is based on Vasconia, a marker Availability and reliability of infrastructure broadly used in the Llanos Basin, adjusted for certain marketing and quality Our business depends on the availability and reliability of operating and discounts based on, among other things, API, viscosity, sulfur, delivery point transportation infrastructure in the areas in which we operate. Prices and and water content, as well as on certain transportation costs (including availability for equipment and infrastructure, and the maintenance thereof, pipeline costs and trucking costs). affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key In Chile, the price of oil we sell to ENAP is based on Brent minus certain Information—D. Risk factors—Risks relating to our business—Our inability to marketing and quality discounts. We have a long-term gas supply contract access needed equipment and infrastructure in a timely manner may hinder with Methanex. The price of the gas sold under this contract is determined our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.” GeoPark 109 Production levels Geographical segment reporting Our oil and gas production levels are heavily influenced by our drilling results, In the description of our results of operations that follow, our “Other” our acquisitions and to oil and natural gas prices. operations reflect our non-Colombian, non-Chilean, non-Argentine and non-Brazilian operations, primarily consisting of our corporate head office We expect that fluctuations in our financial condition and results of operations operations. will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given We divide our business into five geographical segments—Colombia, Chile, well will decline over time. See “Item 3. Key Information—D. Risk factors— Brazil, Argentina and Peru—that correspond to our principal jurisdictions of Risks relating to our business—Unless we replace our oil and natural gas operation. Activities not falling into these five geographical segments are reserves, our reserves and production will decline over time. Our business is reported under a separate corporate segment that primarily includes certain dependent on our continued successful identification of productive fields and corporate administrative costs not attributable to another segment. prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.” Description of principal line items The following is a brief description of the principal line items of our statement Contractual obligations of income. In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods Revenue specified in our various special contracts, E&P Contracts and concession Revenue includes the sale of crude oil, condensate and natural gas net of agreements. The costs to maintain or operate our licensed areas may value-added tax (“VAT”), and discounts related to the sale (such as API and fluctuate or increase significantly, and we may not be able to meet our mercury adjustments) and overriding royalties due to the ex-owners of oil and commitments under these agreements on commercially reasonable terms gas properties where the royalty arrangements represent a retained working or at all, which may force us to forfeit our interests in such areas. If we interest in the property. Revenue is recognized when control has been do not succeed in renewing these agreements, or in securing new ones, transferred to the purchaser and if revenue can be measured reliably and is our ability to grow our business may be materially impaired. See “Item 3. expected to be received. Key Information—D. Risk factors—Risks relating to our business—Under the terms of some of our various CEOPs, E&P Contracts and concession Commodity risk management contracts agreements, we are obligated to drill wells, declare any discoveries and file Includes realized and unrealized gains and losses arising from commodity risk periodic reports in order to retain our rights and establish development management contracts. areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concessioned areas.” Production and operating costs Acquisitions Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve As described above, part of our strategy is to acquire and consolidate assets the revenue for the year. Direct and indirect costs of raw materials and in Latin America. We intend to continue to selectively acquire companies, consumables, rentals, leasing and royalties are also included within this producing properties and concessions. As with our historical acquisitions, account. For a description of our production and operating costs, see “— any future acquisitions could make year-to-year comparisons of our results of Factors affecting our results of operations.” operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future acquisitions. We generally Depreciation and write-off of unsuccessful efforts incorporate our acquired business into our results of operations at or around Capitalized costs of proved oil and natural gas properties are depreciated on the date of closing. a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Functional and presentational currency Petroleum Resources Management System methodology promulgated by the Our Consolidated Financial Statements are presented in US$, which is our Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), presentational currency. Items included in the financial information of each which differs from SEC reporting guidelines pursuant to which certain of our entities are measured using the currency of the primary economic information in the forepart of this annual report is presented. The calculation environment in which the entity operates, or the functional currency, which of the “unit of production” depreciation takes into account estimated future is the US$ in each case, except for our Brazil operations, where the functional discovery and development costs. Changes in reserves and cost estimates are currency is the real. recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. 110 GeoPark 20F In particular, upon completion of the evaluation phase, a prospect is either Profit or loss for the period attributable to owners of the Company transferred to oil and gas properties if it contains reserves or is charged to Profit or loss for the period attributable to owners of the Company consists of profit and loss in the period in which the determination is made. See “— profit or losses for the year less non-controlling interest. Critical accounting policies and estimates—Oil and gas accounting.” Critical accounting policies and estimates Geological and geophysical expenses We prepare our Consolidated Financial Statements in accordance with IFRS Geological and geophysical expenses are recognized on the accrual basis of and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as accounting and consist of geosciences costs, including wages and salaries adopted by the IASB. The preparation of the financial statements requires and share-based compensation not subject to capitalization, geological us to make judgments, estimates and assumptions that affect the reported consultancy costs and costs relating to independent reservoir engineer amounts of assets, liabilities, revenue and expenses, and related disclosure studies. Administrative expenses of contingent assets and liabilities. We continually evaluate these estimates and assumptions based on the most recently available information, our own historical experience and various other assumptions that we believe to be Administrative expenses are recognized on the accrual basis of accounting reasonable under the circumstances. Since the use of estimates is an integral and consist of corporate costs such as director fees and travel expenses, component of the financial reporting process, actual results could differ new project evaluations and back-office expenses principally comprised of from those estimates. wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions. An accounting policy is considered critical if it requires an accounting Our administrative expenses for the year ended December 31, 2018 uncertain at the time such estimate is made, and if different accounting increased by US$10.0 million, or 24%, compared to the year ended estimates that reasonably could have been used, or changes in the December 31, 2017 mainly due to higher staff costs resulting from increased accounting estimates that are reasonably likely to occur periodically, could scale of operations. However, administrative costs may increase as a result materially impact the financial statements. We believe that the following of our Peruvian and Argentinian operations, other acquisitions, increased accounting policies represent critical accounting policies as they involve a activity or the impact of appreciation of local currencies in the countries higher degree of judgment and complexity in their application and require estimate to be made based on assumptions about matters that are highly where we operate. Selling expenses us to make significant accounting estimates. The following descriptions of critical accounting policies and estimates should be read in conjunction with our Consolidated Financial Statements and the accompanying notes Selling expenses are recognized on the accrual basis of accounting and consist and other disclosures. primarily of transportation, storage costs and selling taxes. Business combinations Impairment of non-financial assets Business combinations are accounted for using the acquisition method. Assets that are not subject to depreciation and/or amortization (such as The cost of an acquisition is measured as the fair market value of the assets exploration and evaluation assets) are tested annually for impairment. acquired, equity instruments issued and liabilities incurred or assumed on Assets that are subject to depreciation and/or amortization are reviewed for the date of completion of the acquisition. Acquisition costs incurred are impairment whenever events or changes in circumstances indicate that the recognized directly in the consolidated statement of income. Identifiable carrying amount may not be recoverable. assets acquired and liabilities and contingent liabilities assumed in a An impairment loss is recognized for the amount by which the asset’s carrying acquisition date. The excess of the cost of acquisitions over fair market value amount exceeds its recoverable amount. The recoverable amount is the higher of a company’s share of the identifiable net assets acquired is recorded as of an asset’s fair value minus costs to sell and value in use. goodwill. If the cost of the acquisition is less than a company’s share of the net assets acquired, the difference is recognized directly in the consolidated business combination are measured initially at their fair market values at the During 2018 we recognized a net reversal of impairment losses of US$5.0 statement of income. million, while in 2017 we did not recognize or reverse any impairment losses and in 2016 we recognized a reversal of impairment losses of US$5.7 million. The determination of fair value of identifiable acquired assets and assumed See Note 36 to our Consolidated Financial Statements. liabilities means that we are to make estimates and use valuation techniques, Financial costs including independent appraisers. The valuation assumptions underlying each of these valuation methods are based on available updated information, Financial results include interest expenses, interest income, bank charges, the including discount rates, estimated cash flows, market risk rates and other amortization of financial assets and liabilities, and foreign exchange gains and losses. GeoPark 111 data. As a result, the process of identification and the related determination of drilling costs of exploratory wells. No depreciation and/or amortization are fair values require complex judgments and significant estimates. charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas Cash flow estimates for impairment assessments properties or charged to expense in the period in which the determination Cash flow estimates for impairment assessments require assumptions is made, depending whether they have found reserves. If not developed, about two primary elements: future prices and reserves. Estimates of exploration and evaluation assets are written off after three years, unless future prices require significant judgments about highly uncertain future it can be clearly demonstrated that the carrying value of the investment events. Historically, oil and natural gas prices have exhibited significant is recoverable. All field development costs are considered construction volatility. Our forecasts for oil and natural gas revenues are based on prices in progress until they are finished and capitalized within oil and gas derived from future price forecasts among industry analysts, as well as our properties, and are subject to depreciation once completed. Such costs own assessments. Estimates of future cash flows are generally based on may include the acquisition and installation of production facilities, assumptions of long-term prices and operating and development costs. development drilling costs (including dry holes, service wells and seismic The process of estimating reserves requires significant judgments and acquisition costs of rights and concessions related to proved properties. surveys for development purposes), project-related engineering and the decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas Workovers of wells made to develop reserves and/or increase production reserves and related future net cash flows was performed based on the D&M are capitalized as development costs. Maintenance costs are charged to Reserves Report. Such estimates incorporate many factors and assumptions income when incurred. including: • expected reservoir characteristics based on geological, geophysical and Capitalized costs of proved oil and gas properties and production facilities engineering assessments; and machinery are depreciated on a licensed area by licensed area basis, • future production rates based on historical performance and expected future using the unit of production method, based on commercial proved and operating and investment activities; probable reserves. The calculation of the “unit of production” depreciation • future oil and natural gas prices and quality differentials; takes into account estimated future finding and development costs, and is • anticipated effects of regulation by governmental agencies; and based on current year-end un-escalated price levels. Changes in reserves • future development and operating costs. and cost estimates are recognized prospectively. Reserves are converted to Our management believes these factors and assumptions are reasonable based on the information available at the time we prepare our estimates. Oil and gas reserves for purposes of our Consolidated Financial Statements However, these estimates may change substantially as additional data from are determined in accordance with PRMS, and were estimated by DeGolyer ongoing development activities and production performance becomes and MacNaughton, independent reserves engineers. equivalent units on the basis of approximate relative energy content. available and as economic conditions impacting oil and natural gas prices and costs change. Depreciation of the remaining property, plant and equipment assets (i.e., furniture and vehicles) not directly associated with oil and gas activities For further information related to impairment of property, plant and has been calculated by means of the straight line method by applying equipment, please see Note 36 to our Consolidated Financial Statements. such annual rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between three and 10 years. Oil and gas accounting Oil and gas exploration and production activities are accounted for in Asset retirement obligations accordance with the successful efforts method on a field by field basis. Obligations related to the plugging and abandonment of wells once operations We account for exploration and evaluation activities in accordance with are terminated may result in the recognition of significant liabilities. We record IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing the fair value of the liability for asset retirement obligations in the period in exploration and evaluation costs until such time as the economic viability which the wells are drilled. When the liability is initially recognized, the cost is of producing the underlying resources is determined. Costs incurred prior also capitalized by increasing the carrying amount of the related asset. Over to obtaining legal rights to explore are expensed immediately to the time, the liability is accreted to its present value at each reporting date, and the consolidated statement of income. capitalized cost is depreciated over the estimated useful life of the related asset. Estimating the future abandonment costs is difficult and requires management Exploration and evaluation costs may include: license acquisition, to make assumptions and judgments because most of the obligations will be geological and geophysical studies (i.e., seismic), direct labor costs and settled after many years. Technologies and costs are constantly changing, as 112 GeoPark 20F are political, environmental, health, safety and public relations considerations. In addition, we have tax-loss carry-forwards in certain taxing jurisdictions Consequently, the timing and future cost of dismantling and abandonment that are available to offset against future taxable profit. However, deferred are subject to significant modification. Any change in the variables underlying tax assets are recognized only to the extent that it is probable that taxable our assumptions and estimates can have a significant effect on the liability profit will be available against which the unused tax losses can be utilized. and the related capitalized asset and future charges related to the retirement Management judgment is exercised in assessing whether this is the case. obligations. The present value of future costs necessary for well plugging and abandonment is calculated for each area at the present value of the estimated To the extent that actual outcomes differ from management’s estimates, future expenditure. The liability recognized is based upon estimated future taxation charges or credits may arise in future periods. abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. Share-based payments Contingencies From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, We provide several equity-settled, share-based compensation plans to certain commercial, environmental and health & safety matters. For example, from employees and third-party contractors, composed of payments in the form of time to time, the Company receives notices of environmental, health and safety share awards and stock options plans. violations. Based on what our Management currently knows, such claims are Fair value of the stock option plans for employee or contractor services received in exchange for the grant of the options is recognized as an expense. Recent accounting pronouncements The total amount to be expensed over the vesting period, which is the period See Note 2.1.1 to our Consolidated Financial Statements. over which all specified vesting conditions are to be satisfied, is determined by reference to the fair value of the options granted calculated using the We have set up a project team by business unit which has reviewed each Geometric Brownian Motion method. Determining the total value of our business unit’s leasing arrangements over the last year in light of the new not expected to have a material impact on the financial statements. share-based payments requires the use of highly subjective assumptions, lease accounting rules in IFRS 16. including the expected life of the stock options, estimated forfeitures and the price volatility of the underlying shares. The assumptions used in As of December 31, 2018, we have non-cancellable operating lease calculating the fair value of share-based payment represent management’s commitments of US$ 69.9 million. Of these commitments, we expect to best estimates, but these estimates involve inherent uncertainties and the recognize right-of-use assets and lease liabilities, at nominal value, of application of management’s judgment. approximately US$ 14.5 million on January 1, 2019. The remaining lease commitments, in accordance with IFRS 16, will be recognized on a straight-line Non-market vesting conditions are included in assumptions in respect of basis as expense in the consolidated statement of income. the number of options that are expected to vest. At each balance sheet date, we revise our estimates of the number of options that are expected to vest. There will not be an impact on Adjusted EBITDA as a consequence of the We recognize the impact of the revision to original estimates, if any, in the adoption of this new standard. consolidated statement of income, with a corresponding adjustment to equity. Operating cash flows will increase and financing cash flows will decrease by approximately US$ 4 million, as repayment of the principal portion of the lease The fair value of the share awards payments is determined at the grant date by liabilities will be classified as cash flows from financing activities. reference of the market value of the shares and recognized as an expense over the vesting period. We have applied the standard from the mandatory adoption date of January 1, 2019. We intend to apply the simplified transition approach and as a result, will When options are exercised, we issue new common shares. The proceeds not restate comparative amounts for the year prior to first adoption. received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium when the options are exercised. Results of operations Taxation The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our The computation of our income tax expense involves the interpretation of Consolidated Financial Statements and the accompanying notes. applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by us, through negotiations with relevant tax authorities or In preparation for continued volatility, we have developed multiple scenarios through litigation, can take several years to complete and in some cases it is for our 2019 capital expenditure program. See “Item 4. Information on the difficult to predict the ultimate outcome. Company –B. Business Overview—2019 Strategy and Outlook.” GeoPark 113 Year ended December 31, 2018 compared to year ended December 31, 2017 The following table summarizes certain of our financial and operating data for the years ended December 31, 2018 and 2017. For the year ended December 31 (in thousands of US$, except for percentages) % Change from 2018 2017 prior year Revenue Net oil sales Net gas sales Revenue 545,490 55,671 279,162 50,960 601,161 330,122 Commodity risk management contracts 16,173 Production and operating costs (174,260) Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful exploration efforts Impairment loss reversed for non-financial assets Other operating expense Operating profit Financial expenses Financial income Foreign exchange loss Profit before income tax Income tax expense Profit (Loss) for the year Non-controlling interest Profit (Loss) for the year attributable to owners of the Company Net production volumes Oil (mbbl)(2) Gas (mcf )(3) Total net production (mboe) Average net production (boepd) Average realized sales price Oil (US$ per bbl) Gas (US$ per mmcf ) (1) Calculated pursuant to FASB ASC 932 (2) We present production figures before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes. Oil production figures Average unit costs per boe (US$) presented on page F-75 are net of royalties. (3) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on page F-76 is gas measured at the point of Operating cost Royalties and other Production costs(1) Geological and geophysical expenses delivery. 114 GeoPark 20F Administrative expenses Selling expenses 95% 9% 82% (205)% 76% 81% 24% 254% 23% (15,448) (98,987) (7,694) (42,054) (1,136) (74,885) (13,951) (52,074) (4,023) (92,240) (26,389) (5,834) 352% 4,982 (2,887) 256,492 (39,321) 3,059 (11,323) 208,907 (106,240) 102,667 30,252 - (5,088) 78,996 (53,511) 2,016 (2,193) 25,308 (43,145) (17,837) 6,391 100% (43)% 225% (27)% 52% 416% 725% 146% 676% 373% 72,415 (24,228) 399% 11,113 12,219 13,150 36,027 8,309 10,562 10,069 27,586 53.0 5.1 8.2 5.8 14.0 1.1 4.2 0.3 36.6 5.3 7.4 3.0 10.4 0.8 4.4 0.1 34% 16% 31% 24% 46% (4)% 11% 93% 35% 38% -5% 200% The following table summarizes certain financial and operating data. For the year ended December 31, (in thousands of US$) 2018 2017 Chile Colombia Brazil Argentina Peru Other Total Chile Colombia Brazil Other Total 37,359 (28,203) 497,870 30,053 35,879 - - 601,161 32,738 263,076 34,238 70 330,122 (42,721) (10,395) (10,640) (245) (36) (92,240) (23,730) (40,010) (10,809) (336) (74,885) (12,670) (6,134) (2,020) (583) - - (21,407) (546) (1,625) (2,978) (685) (5,834) Revenue Depreciation Impairment and write-off Revenue For the year ended December 31, 2018, crude oil sales were our principal US$51.0 million for the year ended December 31, 2017 to US$55.7 million source of revenue, with 91% and 9% of our total revenue from crude oil for the year ended December 31, 2018 due to increased sales volumes, the and gas sales, respectively. The following chart shows the change in oil and addition of the acquired blocks in Argentina and higher realized prices. natural gas sales from the year ended December 31, 2017 to the year ended December 31, 2018. The increase in 2018 net revenue of US$271.0 million is mainly explained by: • an increase of US$234.8 million in sales in Colombia, due to higher realized For the year ended December 31, prices and increased deliveries; (in thousands of US$) • an increase of US$4.6 million in sales in Chile, due to higher realized prices; • a decrease of US$4.2 million in gas sales in Brazil, primarily related to lower 2018 2017 gas prices; • an increase of US$35.8 million in sales in Argentina from the acquired 545,490 55,671 blocks; 279,162 50,960 Revenue attributable to our operations in Colombia for the year ended 601,161 330,122 December 31, 2018 was US$497.9 million, compared to US$263.1 million for the year ended December 31, 2017, representing 83% and 80% of our total consolidated sales. The increase is related to an increase in oil deliveries from Year ended December 31 Change from prior year 7.6 mmbbl to 10.0 mmbbl and an increase in the average realized price per (in thousands of US$, except for percentages) barrel of crude oil from US$36.1 per barrel to US$52.6 per barrel, primarily due 2018 2017 % to higher reference international prices. 497,870 263,076 234,794 37,359 30,053 35,879 32,738 34,238 70 4,621 (4,185) 35,809 89% 14% Revenue attributable to our operations in Chile for the year ended December 31, 2018 was US$37.4 million, a 14% increase from US$32.7 million for the year (12)% ended December 31, 2017, principally due to (1) increased average realized 51,156% prices per barrel of crude oil from US$45.7 per barrel for the year December 31, 601,161 330,122 271,039 82% 2017 to US$62.3 per barrel for the year ended December 31, 2018 (an increase of US$16.6 per barrel or a total of 36%), and (2) an increase in gas sales by Consolidated Sale of crude oil Sale of gas Total By country Colombia Chile Brazil Argentina Total Revenue increased 82%, from US$330.1 million for the year ended December US$3.1 million reflecting higher gas prices and higher deliveries, mainly as a 31, 2017 to US$601.1 million for the year ended December 31, 2018, primarily result of the discovery of the Jauke gas field. This was partially offset by sales as a result of higher realized prices and additional deliveries. Sales of crude of crude oil of 0.2 mmbbl for the year ended December 31, 2018 compared oil increased due to higher realized prices and higher sold volumes of 10.7 to 0.3 mmbbl for the year ended December 31, 2017 (a decrease of 20%) due mmbbl in the year ended December 31, 2018 compared to 7.9 mmbbl in to the decline in oil base production. The contribution to our revenue during the year ended December 31, 2017, and resulted in net revenue of US$545.5 such years from our operations in Chile was 6%, respectively. million for the year ended December 31, 2018 compared to US$279.2 million for the year ended December 31, 2017. In addition, sales of gas increased from GeoPark 115 Revenue attributable to our operations in Brazil for the year ended December 31, 2018 was US$30.0 million, a 12% decrease from US$34.2 million for the year ended December 31, 2017, principally due to lower gas prices and deliveries. The contribution to our revenue from our operations in Brazil during the years ended December 31, 2018 and 2017 was 5% in each year. Revenue attributable to our operations in Argentina, primarily from the acquired blocks in Argentina, for the year ended December 31, 2018 was US$ 35.9 million, representing 6% of our total consolidated sales. The average realized price per barrel of crude oil increased from US$52.3 per barrel to US$65.0 per barrel. Production and operating costs The following table summarizes our production and operating costs for the years ended December 31, 2018 and 2017. For the year ended December 31 (in thousands of US$, except for percentages) % Change from prior 2018 2017 year Consolidated (including Colombia, Chile, Argentina, Peru and Brazil) Royalties Staff costs Operation and maintenance Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (71,836) (18,603) (7,756) (2,628) (20,262) (17,444) (9,317) (26,414) (28,697) (12,358) (3,116) (2,969) (14,722) (11,902) (5,818) (19,405) (174,260) (98,987) 150% 51% 149% (11)% 38% 47% 60% 36% 76% Year ended December 31 (in thousands of US$) 2018 2017 Chile Brazil Argentina Colombia Chile Brazil Argentina Colombia (1,473) (6,521) - (1,250) (4,095) (1,712) (287) (6,561) (21,899) (2,820) (386) - - (1,286) - - (4,293) (8,785) (4,833) (3,167) (2,877) (120) (6,044) (1,018) (1,269) (5,715) (62,710) (8,529) (4,879) (1,258) (8,837) (14,714) (7,761) (9,845) (1,314) (5,582) - (1,211) (3,817) (1,680) (59) (7,336) (3,134) (241) - - (2,982) - - (4,380) (13) (190) - (80) - (12) (53) 10 (24,236) (6,345) (3,116) (1,678) (7,923) (10,209) (5,706) (7,700) (25,043) (118,533) (20,999) (10,737) (338) (66,913) By country Royalties Staff costs Operation and maintenance Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total 116 GeoPark 20F Consolidated production and operating costs increased 76%, from US$99.0 Administrative costs million for the year ended December 31, 2017 to US$174.3 million for the year ended December 31, 2018, primarily due to the new operation of the blocks Year ended December 31 Change from prior year in Argentina, higher royalties paid in cash, in line with increased production (in thousands of US$, except for percentages) and a higher royalty rate in Colombia, and increased operating costs related to higher sales volumes. Production and operating costs in Colombia increased 77%, to US$118.5 Colombia Chile Brazil million for the year ended December 31, 2018, as compared to US$66.9 million Argentina for the year ended December 31, 2017, primarily due to higher royalties of US$38.5 million, in line with increased production, a higher royalty rate and Other Total higher oil prices. In addition, operating costs per boe in Colombia remained at 2018 2017 (24,910) (17,567) (7,343) (5,671) (2,628) (2,847) (6,331) (2,444) (2,057) 660 (184) (790) (16,018) (13,655) (2,363) (52,074) (42,054) (10,020) % 42% (10)% 8% 38% 17% 24% US$5.6 per boe for the year ended December 31, 2018. Administrative costs increased 24%, from US$42.1 million for the year ended December 31, 2017 to US$52.1 million for the year ended December 31, 2018, Production and operating costs in Chile increased by 4% to US$21.9 million mainly due to higher consultant fees and travel expenses for an amount of due to higher staff costs expenses and pulling campaign. Costs per boe US$3.3 million, higher staff costs for an amount of US$2.7 million and higher increased to US$22.8 per boe from US$20.3 per boe in 2017. In the year ended other expenses related to our growth strategy and new business. December 31, 2018, the revenue mix for Chile was 46.6% oil and 53.4% gas, whereas for the same period in 2017 it was 48.5% oil and 51.5% gas. Selling expenses Production and operating costs in Brazil decreased by 18%, to US$8.8 million for the year ended December 31, 2018, as compared to the year ended December 31, 2017, mainly resulting from non-recurring maintenance costs in Colombia Manati Field. Operating costs per boe decreased to US$6.1 for the year ended Chile December 31, 2018 from US$7.8 per boe for the year ended December 31, Argentina 2017. Total Year ended December 31, Change from prior year (in thousands of US$, except for percentages) 2018 (1,028) (533) (2,462) (4,023) 2017 (250) (688) (198) (1,136) (778) 155 (2,264) (2,887) % 311% (23)% 1143% 254% Production and operating costs in Argentina amounted to US$25.0 million Selling expenses increased 254%, from US$1.1 million for year ended December for the year ended December 31, 2018, mainly resulting from the operation 31, 2017 to US$4.0 million for the year ended December 31, 2018, primarily due of the blocks we acquired in Neuquén. Operating costs per boe amounted to to transportation costs and selling taxes in the Aguada Baguales, El Porvenir and US$31.2 for the year ended December 31, 2018. Puesto Touquet blocks in Argentina. Geological and geophysical expenses Commodity risk management contracts Year ended December 31 Change from prior year contracts for the year ended December 31, 2018 and a loss of US$15.4 million (in thousands of US$, except for percentages) for the year ended December 31, 2017. Realized losses reflect cash settled We recorded a profit of US$16.2 million related to commodity risk management % transactions and unrealized losses reflect non-cash changes between the contract values and the forward Brent oil curve. Colombia Chile Brazil Argentina Other Total 2018 (6,288) (733) (827) (1,694) (4,409) (13,951) 2017 (2,231) (858) (1,007) (22) (3,576) (7,694) (4,057) 125 180 (1,672) (833) (6,257) 182% (15)% (18)% 7,600% 23% 81% Geological and geophysical expenses increased 81%, from US$7.7 million for the year ended December 31, 2017 to US$14.0 million for the year ended December 31, 2018, primarily as the result of lower allocation to capitalized Argentina projects in Colombia due to: (i) decreased exploratory drilling activity levels totalling US$4.1 million, (ii) the new operation of the blocks in Argentina Other Total which increased US$1.7 million and (iii) a higher level of activities in Peru for an amount of US$0.5 million. Depreciation Colombia Chile Brazil Year ended December 31, Change from prior year (in thousands of US$, except for percentages) 2018 (42,721) (28,203) (10,395) (10,640) (281) 2017 (40,010) (23,730) (10,809) (159) (177) (2,711) (4,473) 414 (10,481) (104) (92,240) (74,885) (17,355) % 7% 19% (4)% 66% 59% 23% GeoPark 117 Depreciation charges increased by 23% from US$74.9 million for the year ended real in the 2017 and 2018 period. Foreign exchange differences are mainly December 31, 2017 to US$92.2 million for the year ended December 31, 2018, generated from changes in the value of the Brazilian real over the U.S. Dollar- mainly due to the new operation of the blocks in Argentina and increased denominated debt incurred at the local subsidiary level, where the functional volumes. However, depreciation costs per boe decreased from US$7.9 to US$7.1 currency is the Brazilian real. per boe due to drilling successes and increased reserves in Colombia. Profit before income tax Operating profit (loss) Year ended December 31, Change from prior year (in thousands of US$, except for percentages) 2018 309,357 (29,139) 4,370 (6,739) (21,357) 256,492 2017 116,290 (19,675) 4,434 (3,430) (18,623) 78,996 193,067 (9,464) (64) (3,309) (2,734) % Colombia 166% 48% (1)% 96% 15% Chile Brazil Argentina Other Total 177,496 225% Colombia Chile Brazil Argentina Other Total Year ended December 31 Change from prior year (in thousands of US$, except for percentages) 2018 305,409 (40,545) (6,632) (13,737) (35,588) 208,907 2017 113,028 (32,801) (2,529) (4,845) (47,545) 25,308 192,381 (7,744) (4,103) (8,892) 11,957 183,599 % 170% 24% 162% 184% (25)% 725% We recorded an operating profit of US$256.5 million for the year ended of US$208.9 million, compared to a profit of US$25.3 million for the year ended December 31, 2018, a 225% improvement from the operating profit of December 31, 2017, primarily due to profits recorded in our Colombian operations. US$79.0 million for the year ended December 31, 2017, primarily due to an increase in revenue and other gains, as described above. Income tax expense Year ended December 31 Change from prior year For the year ended December 31, 2018, we recorded a profit before income tax In 2018, we recorded a write-off of unsuccessful exploration efforts of 2018 2017 US$26.4 million that corresponded to nine unsuccessful exploratory wells, Colombia (119,730) (45,406) (74,324) four wells drilled in Colombia (Tiple, Llanos 34 and Llanos 32 Blocks), two wells drilled in Brazil (POT-T-747 and POT-T-619 Blocks) and three wells Chile Brazil drilled in Argentina (Puelen Block). The charge also included the write-off of Argentina a well and other exploration costs incurred in the Fell Block in previous years Other 6,090 1,762 5,752 (114) 856 36 - 5,234 1,726 5,752 1,369 (1,483) and other exploration costs incurred in the VIM-3 Block, and POT-T-882 and Total (106,240) (43,145) (63,095) % 164% 611% 4,794% 100% (108)% 146% (in thousands of US$, except for percentages) REC-T-93 Blocks, for which no additional work would be performed. This was partially offset by a gain on non-cash impairments reversal of non-financial assets amounting to US$5.0 million. This amount comprised: (i) US$11.5 million gain in Colombia, resulting from an improved oil price environment Our effective tax rate was 51% for the year ended December 31, 2018, compared to and the known fair value less costs of disposal of the La Cuerva and Yamu 170% in 2017. The decrease in the effective tax rate was primarily due to an increase in Blocks; and (ii) US$6.5 million impairment loss due to the termination of the profits recorded in our Colombian operations as compared to the other countries and sales agreement for the TdF’s blocks, with no renovation in place as of the the incorporation of the Argentine operations. date of this annual report. Financial costs Profit (loss) for the year Financial costs decreased 30% to US$36.3 million for the year ended December Year ended December 31 Change from prior year 31, 2018 as compared to US$51.5 million for the year ended December 31, 2017, mainly due to one-time costs on the cancellation of 2020 Notes for an amount of US$17.6 million recognized in 2017. Foreign exchange (loss) gain Colombia Chile Brazil Foreign exchange variation increased from a loss of US$2.2 million for the year Argentina ended December 31, 2017 compared to a loss of US$11.3 million for the year ended December 31, 2018, mainly due to the depreciation of the Brazilian Other Total (in thousands of US$, except for percentages) 2018 185,679 (34,455) (4,870) (7,985) 2017 67,622 (31,945) (2,493) (4,845) (35,702) (46,176) 118,057 (2,510) (2,377) (3,140) 10,474 102,667 (17,837) 120,504 % 175% 8% 95% 65% (23)% (676)% 118 GeoPark 20F For the year ended December 31, 2018, we recorded a net profit of US$102.7 million as a result of the reasons described above. Profit for the year attributable to owners of the Company For the year ended December 31 (in thousands of US$, except for percentages) % Change from Profit for the year attributable to owners of the Company increased by 399% 2017 2016 prior year to US$72.4 million, compared to a loss for the year ended December 31, Revenue 2017 of US$24.2 million for the reasons described above. Profit attributable Net oil sales to non-controlling interest increased by 373% to US$30.3 million for the year Net gas sales ended December 31, 2018 as compared to a profit of US$6.4 million for the Revenue 279,162 50,960 145,193 47,477 330,122 192,670 year ended December 31, 2017. In November 2018, we acquired all of LGI’s Commodity risk management contracts (15,448) equity interest in GeoPark’s Chilean and Colombian subsidiaries. Production and operating costs Geological and geophysical expenses Year ended December 31, 2017 compared to year ended December 31, 2016 Administrative expenses The following table summarizes certain of our financial and operating data for Selling expenses the years ended December 31, 2017 and 2016. Depreciation (98,987) (7,694) (42,054) (1,136) (74,885) (2,554) (67,235) (10,282) (34,170) (4,222) (75,774) 92% 7% 71% 505% 47% (25)% 23% (73)% (1)% Write-off of unsuccessful exploration efforts Impairment loss reversed for non-financial assets Other operating expense Operating profit (loss) Financial costs Foreign exchange (loss) gain Profit (Loss) before income tax Income tax expense Loss for the year Non-controlling interest Loss for the year attributable (5,834) (31,366) (81)% - (5,088) 78,996 (51,495) (2,193) 25,308 (43,145) 5,664 (1,344) (28,613) (34,101) 13,872 (48,842) (11,804) (17,837) (60,646) 6,391 (11,554) (100)% 279% (376)% 51% (116)% (152)% 266% (71)% (155)% to owners of the Company (24,228) (49,092) (51)% Net production volumes Oil (mbbl)(2) Gas (mcf )(3) Total net production (mboe) Average net production (boepd) Average realized sales price Oil (US$ per bbl) Gas (US$ per mmcf ) Average unit costs per boe (US$) Operating cost Royalties and other Production costs(1) Geological and geophysical expenses Administrative expenses Selling expenses 8,309 10,562 10,069 27,586 6,189 11,911 8,174 22,394 36.6 5.3 7.4 3.0 10.4 0.8 4.4 0.1 25.6 4.5 7.3 1.5 8.8 1.3 4.5 0.6 34% (11)% 23% 23% 43% 18% 1% 100% 18% (38)% (2)% (83)% (1) Calculated pursuant to FASB ASC 932 (2) We present production figures before deduction of royalties, as we believe that net production before royalties is more appropriate in light of our foreign operations and the attendant royalty regimes. Oil production figures presented on page F-75 are net of royalties. (3) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on page F-76 is gas measured at the point of delivery. GeoPark 119 The following table summarizes certain financial information and operating data. Revenue Depreciation Impairment and write-off Chile Colombia 32,738 (23,730) (546) 263,076 (40,010) (1,625) Brazil 34,238 (10,809) (2,978) Other 70 (336) (685) Revenue For the year ended December 31, (in thousands of US$) 2017 Total 330,122 (74,885) (5,834) Chile Colombia 36,723 (31,355) (19,389) 126,228 (31,148) (1,730) Brazil 29,719 (12,974) (4,583) Other - (297) - 2016 Total 192,670 (75,774) (25,702) For the year ended December 31, 2017, crude oil sales were our principal for the year ended December 31, 2016 to US$51.0 million for the year ended source of revenue, with 85% and 15% of our total revenue from crude oil December 31, 2017 due to increased sales volumes and higher realized prices. and gas sales, respectively. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2016 to the year ended The increase in 2017 net revenue of US$137.5 million is mainly explained by: December 31, 2017. • an increase of US$136.8 million in sales in Colombia, due to an increase in price and volume; For the year ended December 31, • a decrease of US$4 million in sales in Chile, including decreases of US$2.9 (in thousands of US$) million in oil sales and US$1.1 million of gas sales; and • an increase of US$4.3 million in gas sales in Brazil, related to our Manati 2017 2016 operations; 279,162 50,960 145,193 all of which was due principally to higher oil and gas prices, as further 47,477 described below. 330,122 192,670 Revenue attributable to our operations in Colombia for the year ended December 31, 2017 was US$263.1 million, compared to US$126.2 million for Year ended December 31 the year ended December 31, 2016, representing 80% and 66% of our total (in thousands of US$, except for percentages) consolidated sales. The increase is related to an increase in oil deliveries from % Change 5.4 mmbbl to 7.6 mmbbl and an increase in the average realized price per from prior barrel of crude oil from US$24.4 per barrel to US$36.1 per barrel, primarily 2017 2016 year due to higher reference international prices. 263,076 126,228 136,848 32,738 34,238 70 36,723 29,719 - (3,985) 4,519 70 108% (11)% Revenue attributable to our operations in Chile for the year ended December 31, 2017 was US$32.7 million, a 11% decrease from US$36.7 million for the 15% year ended December 31, 2016, principally due to (1) decreased sales of 100% crude oil of 0.3 mmbbl for the year ended December 31, 2017 compared to 330,122 192,670 137,452 71% 0.5 mmbbl for the year ended December 31, 2016 (a decrease of 40%) due to the decline in oil base production, (2) a decrease in gas sales by US$1.1 Consolidated Sale of crude oil Sale of gas Total By country Colombia Chile Brazil Other Total Revenue increased 71%, from US$192.7 million for the year ended December million, due to decreased gas production levels as compared to the previous 31, 2016 to US$330.1 million for the year ended December 31, 2017, primarily year. This was partially offset by increased average realized prices per barrel as a result of higher oil revenues. Sales of crude oil increased due to higher of crude oil from US$37.0 per barrel for the year December 31, 2016 to realized prices and higher sold volumes of 7.9 mmbbl in the year ended US$45.7 per barrel for the year ended December 31, 2017 (an increase of December 31, 2017 compared to 5.9 mmbbl in the year ended December US$8.7 per barrel or a total of 24%). The increase in the average realized 31, 2016, and resulted in net revenue of US$279.2 million for the year ended price per barrel was attributable to higher international reference prices. The December 31, 2017 compared to US$145.2 million for the year ended contribution to our revenue during such years from our operations in Chile December 31, 2016. In addition, sales of gas increased from US$47.5 million was 10% and 19%, respectively. 120 GeoPark 20F Revenue attributable to our operations in Brazil for the year ended December 31, 2017 was US$34.2 million, a 15% increase from US$29.7 million for the year ended December 31, 2016, principally due to higher gas prices. The contribution to our revenue from our operations in Brazil during the years ended December 31, 2017 and 2016 was 10% and 15%, respectively. Production and operating costs The following table summarizes our production and operating costs for the years ended December 31, 2017 and 2016. For the year ended December 31 (in thousands of US$, except for percentages) % Change from prior 2017 2016 year Consolidated (including Colombia, Chile, Argentina, Peru and Brazil) Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (28,697) (15,474) (2,969) (14,722) (11,902) (5,818) (19,405) (11,497) (10,859) (2,281) (13,160) (8,283) (3,868) (17,287) (98,987) (67,235) 150% 42% 30% 12% 44% 50% 12% 47% By country Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total Year ended December 31, (in thousands of US$) 2017 2016 Chile Brazil Colombia Chile Brazil Colombia (1,314) (5,582) (1,211) (3,817) (1,680) (59) (7,336) (3,134) (241) - (2,982) - - (4,380) (24,236) (9,461) (1,678) (7,923) (10,209) (5,706) (7,700) (1,495) (5,866) (1,170) (6,122) (1,405) (42) (6,069) (20,999) (10,737) (66,913) (22,169) (2,721) (85) - (1,419) - - (4,234) (8,459) (7,281) (5,530) (1,111) (5,619) (6,878) (3,826) (6,362) (36,607) GeoPark 121 Consolidated production and operating costs increased 47%, from US$67.2 December 31, 2017, primarily as the result of higher allocation to capitalized million for the year ended December 31, 2016 to US$99.0 million for the year projects due to increased drilling activity levels. ended December 31, 2017, primarily due to higher royalties paid in cash, in line with increased production (the Jacana oil field accumulated more than 5 Administrative costs mmbbl during the year ended December 31, 2017, triggering a higher royalty rate in Colombia), and higher oil prices, and increased operating costs related to higher sales volumes. Year ended December 31, (in thousands of US$, except for percentages) Production and operating costs in Colombia increased 83%, to US$66.9 million for the year ended December 31, 2017, as compared to US$36.6 million for the 2017 2016 year ended December 31, 2016, primarily due to (i) higher royalties of US$17.0 Colombia (17,567) (14,715) (2,852) million, in line with increased production (the Jacana oil field accumulated more than 5 mmbbl during the year ended December 31, 2017, triggering a higher royalty rate in Colombia) and higher oil prices, and (ii) increased costs associated with higher production and the reopening of the Cuerva and Yamu Blocks, which are mature fields with higher operating costs than the Llanos 34 Chile Brazil Other Total (6,331) (2,444) (15,712) (7,153) (3,085) (9,217) (42,054) (34,170) 822 641 (6,495) (7,884) % Change from prior year 19% (11)% (21)% 70% 23% Block. In addition, operating costs per boe in Colombia increased to US$5.6 Administrative costs increased 23%, from US$34.2 million for the year ended per boe for the year ended December 31, 2017 from US$5.4 per boe for the December 31, 2016 to US$42.1 million for the year ended December 31, 2017, year ended December 31, 2016. mainly due to higher staff costs and consulting fees resulting from an increased Production and operating costs in Chile decreased by 5% to US$21.0 million due to lower oil and gas production levels. Costs per boe increased to US$20.3 Selling expenses per boe from US$15.8 per boe in 2016. In the year ended December 31, 2017, the revenue mix for Chile was 48.5% oil and 51.5% gas, whereas for the same period in 2016 it was 51.1% oil and 48.9% gas. scale of operations. Production and operating costs in Brazil increased by 27%, to US$10.7 million for the year ended December 31, 2017, as compared to the year ended December 31, 2016, mainly resulting from non-recurring maintenance costs in Colombia Manati Field. Operating costs per boe increased to US$7.8 for the year ended December 31, 2017 from US$5.8 per boe for the year ended December 31, 2016. Geological and geophysical expenses Chile Brazil Other Total Year ended December 31, (in thousands of US$, except for percentages) 2017 (250) (688) - (198) (1,136) 2016 (2,830) (994) (20) (378) 2,580 306 20 180 (4,222) 3,086 % Change from prior year (91)% (31)% (100)% (48)% (73)% Year ended December 31, 31, 2016 to US$1.1 million for the year ended December 31, 2017, primarily (in thousands of US$, except for percentages) due to the Trafigura offtake agreement as sales occur at the wellhead in our % Change Colombian operations, which are recorded as a discount to the oil price. Selling expenses decreased 73%, from US$4.2 million for year ended December Colombia Chile Brazil Other Total 2016 (2,231) (858) (1,007) (3,598) 2015 (4,296) (1,671) (1,053) (3,262) (7,694) (10,282) from prior year Commodity risk management contracts 2,065 813 46 (336) 2,588 (48)% (49)% (4)% 10% (25)% We recorded a loss of US$15.4 million related to commodity risk management contracts for the year ended December 31, 2017. Realized losses reflect cash settled transactions and unrealized losses reflect non-cash changes between the contract values and the forward Brent oil curve. Depreciation Depreciation charges decreased by 1% from US$75.8 million for the year ended Geological and geophysical expenses decreased 25%, from US$10.3 million December 31, 2016 to US$74.9 million for the year ended December 31, 2017, for the year ended December 31, 2016 to US$7.7 million for the year ended mainly due to lower production levels in Chile and Brazil. and lower depreciation 122 GeoPark 20F costs per barrel in Colombia. Depreciation costs per boe decreased from US$9.9 For the year ended December 31, 2017, we recorded a profit before income to US$7.9 per boe. Operating profit (loss) tax of US$25.3 million, compared to a loss of US$48.8 million for the year ended December 31, 2016, primarily due to profits recorded in our Colombian Year ended December 31, operations. (in thousands of US$, except for percentages) Income tax (expense) Colombia Chile Brazil Other Total 2017 116,290 (19,675) 4,434 (22,053) 78,996 2016 31,464 (44,969) (644) (14,464) 84,826 25,294 5,078 (7,589) % Change from prior year 270% (56)% (789)% 52% Colombia (28,613) 107,609 (376)% We recorded an operating profit of US$79.0 million for the year ended December 31, 2017, a 376% improvement from the operating loss of US$28.6 million for the year ended December 31, 2016, primarily due to an increase in Chile Brazil Other Total Year ended December 31, (in thousands of US$, except for percentages) 2017 2016 (45,406) (11,969) 856 36 1,369 2,155 (2,764) 774 (33,437) (1,299) 2,800 595 (43,145) (11,804) (31,341) % Change from prior year 279% (60)% (101)% 77% 266% revenue and other gains and a decrease in certain expenses and depreciation, as Income tax expense increased 266%, from US$11.8 million for the year ended described above. In 2016, we recorded a gain on non-cash impairments reversal December 31, 2016 to US$43.1 million for the year ended December 31, 2017, of non-financial assets amounting to US$5.7 million in Colombia, resulting from as a result of higher profits in Colombia. an improved oil price environment and improvements in cost structure. Loss for the year Financial costs Financial costs increased 51% to US$51.5 million for the year ended December Year ended December 31, 31, 2017 as compared to US$34.1 million for the year ended December 31, 2016, (in thousands of US$, except for percentages) mainly due to one-time costs on the cancellation of 2020 Notes for an amount of US$17.6 million. Foreign exchange (loss) gain Foreign exchange variation decreased from a gain of US$13.9 million for the year ended December 31, 2016 compared to a loss of US$2.2 million for the year ended December 31, 2017, mainly due to the appreciation of the Brazilian real in the 2016 period and its depreciation in the 2017 period. Foreign exchange differences are mainly generated from changes in the value of the Brazilian real Colombia Chile Brazil Other Total 2017 67,622 (31,945) (2,493) (51,021) 2016 13,876 (55,862) 5,998 (24,658) (17,837) (60,646) 53,746 23,917 (8,491) (26,363) 42,809 % Change from prior year 387% (43)% (142)% 107% (71)% over the U.S. Dollar-denominated debt incurred at the local subsidiary level, For the year ended December 31, 2017, we recorded a net loss of US$17.8 where the functional currency is the Brazilian real. million as a result of the reasons described above. Profit (Loss) before income tax Loss for the year attributable to owners of the Company Year ended December 31, Loss for the year attributable to owners of the Company decreased by 51% to (in thousands of US$, except for percentages) US$24.2 million, compared to a loss for the year ended December 31, 2016 of Colombia Chile Brazil Other Total 2017 113,028 (32,801) (2,529) (52,390) 25,308 2016 25,845 (58,017) 8,762 (25,432) (48,842) % Change US$49.1 million for the reasons described above. Profit attributable to non- from prior controlling interest increased by 155% to US$6.4 million for the year ended year December 31, 2017 as compared to a loss of US$11.6 million for the year ended December 31, 2016. 87,183 25,216 (11,291) (26,958) 74,150 337% (43)% (129)% 106% (152)% GeoPark 123 B. Liquidity and capital resources Overview examine measures such as further capital expenditure program reductions, pre-sale agreements, disposition of assets, or issuance of equity, among Our financial condition and liquidity is and will continue to be influenced by a others. variety of factors, including: • changes in oil and natural gas prices and our ability to generate cash flows Capital expenditures from our operations; • our capital expenditure requirements; In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, • the level of our outstanding indebtedness and the interest we are obligated as well as through cash generated from our operations. We expect to incur to pay on this indebtedness; and substantial expenses and capital expenditures as we develop our oil and • changes in exchange rates which will impact our generation of cash flows natural gas prospects and acquire additional assets. See “Item 4. Information from operations when measured in US$, and the real. on the Company –B. Business Overview—2019 Strategy and Outlook.” Our principal sources of liquidity have historically been contributed In the year ended December 31, 2018, we made total capital expenditures shareholder equity, debt financings and cash generated by our operations. We of US$124.7 million (US$97.0 million, US$8.0 million, US$9.0 million, US$8.5 have also in the past entered into offtake and prepayment agreements. million and US$2.3 million in Colombia, Chile, Argentina, Peru and Brazil, Since 2005 to 2018, we have raised approximately US$200 million in equity respectively). offerings at the holding company level and nearly US$1 billion through debt In the year ended December 31, 2017, we made total capital expenditures of arrangements with multilateral agencies such as the IFC, gas prepayment US$105.6 million (US$80.0 million, US$10.2 million, US$8.2 million, US$3.6 facilities with Methanex, international bond issuances and bank financings, million and US$3.6 million in Colombia, Chile, Argentina, Peru and Brazil, described further below, which have been used to fund our capital respectively). expenditures program and acquisitions and to increase our liquidity. Cash flows In February 2014, we commenced trading on the NYSE and raised US$98 The following table sets forth our cash flows for the periods indicated: million (before underwriting commissions and expenses), including the over- allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares. Year ended December 31, (in thousands of US$) In September 2017, we issued US$425.0 million aggregate principal amount Operating activities of senior notes due 2024. The Notes due 2024 mature on September 21, Investing activities 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Financing activities 256,206 142,158 (164,594) (105,604) (97,641) 23,968 Interest on the Notes due 2024 is payable semi-annually in arrears on March Net (decrease) increase in Cash flows provided by (used in) 2018 2017 2016 82,884 (39,306) (51,136) 21 and September 21 of each year. The Indenture governing our Notes due cash and cash equivalents (6,029) 60,522 (7,558) 2024 contains incurrence-based limitations on the amount of indebtedness we can incur. This limits our capacity to incur additional indebtedness, other Cash flows provided by operating activities than permitted debt, as specified in the indenture governing the Notes For the year ended December 31, 2018, cash provided by operating activities due 2024. The net proceeds from the Notes due 2024 were used by us (i) to was US$256.2 million, an 80% increase from US$142.2 million for the year make a capital contribution to our wholly-owned subsidiary, GeoPark Latin ended December 31, 2017, resulting from the increase in oil prices and America Limited Agencia en Chile, providing it with sufficient funds to fully deliveries in 2018 as compared to 2017, net of increased income taxes paid repay the Notes due 2020 and to pay any related fees and expenses, including predominantly from Colombia for an amount of US$60.8 million. a call premium, and (ii) for general corporate purposes, including capital expenditures, such as the acquisition of Aguada Baguales, El Porvenir and For the year ended December 31, 2017, cash provided by operating activities Puesto Touquet blocks in Neuquén Basin in Argentina, and to repay existing was US$142.2 million, a 72% increase from US$82.9 million for the year indebtedness, including the Itaú loan. ended December 31, 2016, resulting from the increase in oil prices in 2017 as compared to 2016, net of a US$15.6 million advance payment paid in We believe that our current operations and 2019 capital expenditures program December 2017 to Pluspetrol, as a security deposit related to the recently can be funded from cash flow from existing operations and cash on hand. announced acquisition of Aguada Baguales, El Porvenir and Puesto Touquet Should our operating cash flow decline due to unforeseen events, including blocks in Neuquén Basin in Argentina. delivery restrictions or a protracted downturn in oil and gas prices, we would 124 GeoPark 20F Cash flows used in investing activities Notes due 2024 For the year ended December 31, 2018, cash used in investing activities was US$164.6 million, a 56% increase from US$105.6 million for the year ended General December 31, 2017. This increase was related to the acquisition of the blocks On September 21, 2017, we issued US$425.0 million aggregate principal in Argentina for an amount of US$48.9 million and capital expenditures amount of senior notes due 2024. The Notes due 2024 mature on September related to development, appraisal and exploration activities. 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in arrears on For the year ended December 31, 2017, cash used in investing activities was March 21 and September 21 of each year. US$105.6 million, a 169% increase from US$39.3 million for the year ended December 31, 2016. This increase was related to higher capital expenditures Ranking in Colombia, Chile, Argentina and Peru in 2017 as compared to 2016. The Notes due 2024 constitute senior unsubordinated obligations of GeoPark Cash flows from financing activities Limited, and are guaranteed by Geopark Chile S.A., Geopark Colombia Coöperatie U.A. (the “Guarantors”). The Notes due 2024 rank equally in right of payment with Cash from financing activities was US$24.0 million for the year ended all existing and future senior obligations of GeoPark Limited and the Guarantors December 31, 2017, compared to US$51.1 million used in financing (except those obligations preferred by operation of law, including without activities for the year ended December 31, 2016. This change was limitation labor and tax claims); rank senior in right of payment to all existing principally related to net proceeds from the issuance of 2024 Notes of and future subordinated indebtedness of GeoPark Limited and the Guarantors; US$418.3 million offset by principal paid of US$355.0 million related to the and rank effectively junior to any secured obligations of GeoPark Limited, the payment of 2020 Notes and the prepayment of the Itaú loan. Guarantors and their respective subsidiaries to the extent of the value of the Cash from financing activities was US$97.6 million for the year ended December 31, 2018, compared to US$24.0 million used in financing Optional redemption collateral securing such obligations. activities for the year ended December 31, 2017. This increase was We may, at our option, redeem all or part of the Notes due 2024, at the principally related to acquisition of the LGI non-controlling interest in redemption prices, expressed as percentages of principal amount, set forth Colombia and Chile’s equity interest for which we paid US$81.0 million. In below, plus accrued and unpaid interest thereon (including additional addition, we paid US$8.0 million for dividends to LGI prior to the acquisition amounts), if any, to the applicable redemption date, if redeemed during the and used US$1.8 million to purchase our own equity securities during 2018. 12-month period beginning on September 21 of the years indicated below: Indebtedness As of December 31, 2018 and 2017, we had total outstanding indebtedness of US$447.0 million and US$426.2 million, respectively, as set forth in the table below. Year 2021 2022 2023 and after Percentage 103.250% 101.625% 100.000% As of December 31, (in thousands of US$) Change of control Bond GeoPark Limited (Notes due 2024) BCI Loans (1) Banco Santander 2018 2017 Upon the occurrence of certain events constituting a change of control, we 426,993 426,124 are required to make an offer to repurchase all outstanding Notes due 2024, 3 20,006 80 - at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in Total 447,002 426,204 respect thereof ) thereon to the date of purchase. If holders of not less than (1) Repaid in February 2019. 90% in aggregate principal amount of the outstanding Notes due 2024 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2024 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus Our material outstanding indebtedness as of December 31, 2018 is accrued and unpaid interest to but excluding the date of such redemption. described below. Covenants The Notes due 2024 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), GeoPark 125 incurrence of liens, guarantees of additional indebtedness, the ability of certain semi-annually, with final maturity in October 2020. subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another Other Agreements company. In December 2015, we entered into an offtake and prepayment agreement with Trafigura under which we sell and deliver a portion of our Colombian crude In the event the Notes due 2024 receive investment-grade ratings from at least oil production. Pricing will be determined by future spot market prices, net of two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, transportation costs. The agreement also provided us with prepayment of up and no default has occurred or is continuing under the indenture governing to US$100 million from Trafigura. Funds committed will be made available to the Notes due 2024, certain of these restrictions, including, among others, the us upon request and will be repaid by us on a monthly basis through future oil limitations on incurrence of debt and disqualified or preferred stock, restricted deliveries over the period of the contract, which is 2.5 years, including a 6-month payments (including restrictions on our ability to pay dividends), the ability of grace period. According to the terms of the prepayment agreement, we are certain subsidiaries to pay dividends, asset sales and certain transactions with required to pay interest of LIBOR plus 5% per year on outstanding amounts. In affiliates will no longer be applicable. addition, under the prepayment agreement, we are required to maintain certain coverage ratios linking: (i) future payments to the value of estimated future The indenture governing our Notes due 2024 includes incurrence test oil deliveries (net of transportation discounts) during the term of the offtake covenants that provide, among other things, that, the net debt to EBITDA ratio agreement and (ii) collections to payments within specified periods, with the should not exceed (i) 3.50 until September 21, 2019, (ii) 3.25 from September possibility of delivering additional volumes to meet such ratios in the upcoming 21, 2019 to September 21, 2021, and (iii) 3.00 thereafter until maturity, and the 3-month period. As of December 31, 2018, it was fully repaid. EBITDA to interest ratio should exceed (i) 2.00 until September 21, 2019, (ii) 2.25 from September 21, 2019 to September 21, 2021 and (iii) 2.50 thereafter until C. Research and development, patents and licenses, etc. maturity. Failure to comply with the incurrence test covenants does not trigger See “Item 4. Information on the Company——B. Business Overview” and “Item 4. an event of default. However, this situation may limit our capacity to incur Information on the Company—B. Business Overview—Title to Properties.” additional indebtedness, as specified in the indenture governing the Notes due 2024, other than certain categories of permitted debt. We must test incurrence D. Trend information covenants before incurring additional debt or performing certain corporate For a discussion of Trend information, see “—A. Operating Results—Factors actions including but not limited to making dividend payments, restricted affecting our results of operations” and “Item 4. Information on the Company payments and others (in each case with certain specific exceptions). –B. Business Overview—2019 Strategy and Outlook.” Events of default E. Off-balance sheet arrangements Events of default under the indenture governing the Notes due 2024 include: We did not have any off-balance sheet arrangements as of December 31, 2018 the nonpayment of principal when due; default in the payment of interest, or as of December 31, 2017. which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change F. Tabular disclosure of contractual obligations of control or as required by certain covenants in the indenture governing In accordance with the terms of our concessions, we are required to pay the Notes due 2024; cross payment default relating to debt with a principal royalties in connection with our crude oil and natural gas production. See amount of US$30.0 million or more, and cross-acceleration default following Note 32.1 to our Consolidated Financial Statements. a judgment for US$30.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2024 to become or to be declared due and payable. Banco Santander During October 2018, we executed a loan agreement with Banco Santander for Brazilian Real 77,640,000 (equivalent to US$ 20,000,000 at the moment of the loan execution) to repay an existing US$-denominated intercompany loan. The interest rate applicable to this loan is the Interbank Certificate of Deposit Rate (“CDI”) plus 2.25% per annum. CDI represents the average rate of all inter- bank overnight transactions in Brazil. The principal and the interest are paid 126 GeoPark 20F Directors, senior management and employees The table below sets forth our committed cash payment obligations as of December 31, 2018. Debt obligations(1) Operating lease obligations(2) Pending investment commitments(3) Asset retirement obligations Total contractual obligations Total 613,693 69,938 45,949 40,317 769,897 Less than one year (in thousands of US$) Three to five years More than five years One to three years 39,545 47,450 37,629 - 124,624 66,273 18,032 8,230 - 92,535 55,250 2,500 90 - 57,840 452,625 1,956 - 40,317 494,898 (1) Refers to principal and interest undiscounted cash flows. Interest payment breakdown included in Debt Obligations is as follows (i) less than one year: US$39.5 million; one to three years: US$66.3 million and three to five years: US$55.3 million. At December 31, 2018, 96% of the outstanding long-term borrowings were issued at fixed rates. See Note 3: “Interest rate risk” to our Consolidated Financial Statements. (2) Reflects the future aggregate minimum lease payments under non- cancellable operating lease agreements. (3) Includes capital commitments in the Isla Norte, Campanario and Flamenco blocks in Chile of US$9.7 million, in the REC-T-94, POT-T-747, REC-T-128 and POT-T-785 blocks in Brazil of US$3.7 million, in the Sierra del Nevado, CN-V and Los Parlamentos blocks in Argentina of US$8.3 million and in the VIM-3 and Llanos 34 blocks in Colombia of US$24.2 million. See “Item 4. Information on the Company—B. Business Overview—Our operations” and Note 32.2 to our Consolidated Financial Statements. G. Safe harbor See “Forward-Looking Statements.” ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES A. Directors and senior management Board of directors Our board of directors is currently composed of eight members. At every annual general meeting, one-third of the Directors retire from office. Our Directors can hold office for such term as the Shareholders may determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. The Directors whose term has expired may offer themselves for re-election at each election of Directors. The term for the current Directors expires on the date of our next annual shareholders’ meeting, to be held in 2019. The current members of the board of directors were appointed at our annual general meeting held on July 27, 2018. The table below sets forth certain information concerning our current board of directors. All ages are as of March 31, 2019. GeoPark 127 Name Position Gerald E. O’Shaughnessy Chairman and Director James F. Park Chief Executive Officer, Deputy Chairman and Director Carlos A. Gulisano Juan Cristóbal Pavez (1)(2) Robert Bedingfield (1)(2) Pedro E. Aylwin Chiorrini Jamie B. Coulter (2) Constantine Papadimitriou (2) (3) Director Director Director Director, Director of Legal and Governance, Corporate Secretary Director Director Age At the Company since 70 63 68 48 70 59 78 58 2002 2002 2010 2008 2015 2003 2017 2018 (1) Member of the Audit Committee. (2) Independent director under SEC Audit Committee rules. (3) Member of the Audit Committee, appointed on March 6, 2019. Science degree in geophysics from the University of California at Berkeley and previously worked as a research scientist in earthquake and tectonic at the University of Texas. In 1978, Jim helped pioneer the development of commercial oil and gas production in Central America with Basic Resources, an Biographical information of the current members of our board of directors is oil and gas exploration company, in Guatemala. He remained a member of the set forth below. Unless otherwise indicated, the current business addresses for board of directors of Basic Resources International Limited until the company our directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile. was sold in 1997. Mr. Park is also a member of the board of directors of Energy Holdings and has also been involved in oil and gas projects in North America, Gerald E. O’Shaughnessy has been our Chairman and a member of our South America, Europe, Middle East and Asia. Mr. Park is a member of the board of directors since he co-founded the company in 2002. Following his AAPG and SPE and has lived in Latin America since 2002. graduation from the University of Notre Dame with degrees in government (1970) and law (1973), Mr. O’Shaughnessy was engaged in the practice of Carlos Gulisano has been a member of our board of directors since June law in Minnesota. Mr. O’Shaughnessy has been active in the oil and gas 2010. Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate business over his entire business career, starting in 1976 with Lario Oil and degree in petroleum engineering and a PhD in geology from the University Gas Company, where he served as Senior Vice President and General Counsel. of Buenos Aires and has authored or co-authored over 40 technical papers. He later formed The Globe Resources Group, a private venture firm whose He is a former adjunct professor at the Universidad del Sur, a former thesis subsidiaries provided seismic acquisition and processing, well rehabilitation director at the University of La Plata, and a former scholarship director at services, sophisticated logistical operations and submersible pump works CONICET, the national technology research council, in Argentina. Dr. Gulisano for Lukoil and other companies active in Russia during the 1990s. Mr. is a respected leader in the fields of petroleum geology and geophysics in O’Shaughnessy is also founder and owner of BOE Midstream, LLC, which owns South America and has over 40 years of successful exploration, development and operates the Bakken Oil Express, a crude by rail transloading and storage and management experience in the oil and gas industry. In addition to terminal in North Dakota, serving oil producers and marketing companies in serving as an advisor to GeoPark since 2002 and as Managing Director from the Bakken Shale Oil play. Over the past 25 years, Mr. O’Shaughnessy has also February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera founded and operated companies engaged in banking, wealth management Argentina San Jorge S.A. and Chevron San Jorge S.A. and has led teams products and services, investment desktop software, computer and network credited with significant oil and gas discoveries, including those in the security, and green clean technology, as well as other venture investments, Mr. Trapial field in Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador, O’Shaughnessy has also served on a number of non-profit boards of directors, Colombia, Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also an including the Board of Economic Advisors to the Governor of Kansas, the I.A. independent consultant on oil and gas exploration and production. O’Shaughnessy Family Foundation, the Wichita Collegiate School, the Institute for Humane Studies, The East West Institute and The Bill of Rights Institute, the Juan Cristóbal Pavez has been a member of our board of directors since Timothy P. O’Shaughnessy Foundation and is a member of the Intercontinental August 2008. He holds a degree in commercial engineering from the Pontifical Chapter of Young Presidents Organization and World Presidents’ Organization. Catholic University of Chile and an MBA from the Massachusetts Institute of Technology. He has worked as a research analyst at Grupo CB and later as a James F. Park has served as our Chief Executive Officer and as a member portfolio analyst at Moneda Asset Management. In 1998, he joined Santana, of our board of directors since co-founding the Company in 2002. He has an investment company, as Chief Executive Officer, where he focused mainly more than 40 years of experience in all phases of the upstream oil and gas on investments in capital markets and real estate. While at Santana, he was business, with a strong background in the acquisition, implementation appointed Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s and management of international projects and teams in North America, main assets. In 1999, Mr. Pavez co-founded Eventures, an internet company. South America, Asia, Europe and the Middle East. He received a Bachelor of Since 2001, he has served as Chief Executive Officer at Centinela, a company 128 GeoPark 20F with a diversified global portfolio of investments. Mr. Pavez is also a board an active participant as an investor in North American shale plays during the member of Grupo Security, Vida Security and Hidroelétrica Totoral. Over the last ten years. Mr. Coulter currently serves as a Director of the Federal Law last few years he has been a board member of several companies, including Enforcement Foundation and is a member of the Board of Trustees for HCA Quintec, Enaex, CTI and Frimetal. Wesley Medical Center, and has previously served on a number of boards of directors, including as a Director of Jimmy Johns LLC, Chairman of the Board Robert Bedingfield has been a member of our board of directors since March of the International Pizza Hut Franchise Holders’ Association, a member of the 2015. He holds a degree in Accounting from the University of Maryland and Board of Advisors of The Wichita State University Center for Entrepreneurship is a Certified Public Accountant. Until his retirement in June 2013, he was one and a member of the Board of Trustees for the University of Kansas School of of Ernst & Young’s most senior Global Lead Partners with more than 40 years Business, among others. of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices, as well as serving on Ernst & Young’s Senior Governing Constantine Papadimitriou as been a member of our board of directors Board. He has extensive experience serving Fortune 500 companies; including since May 2018. He is a respected and successful international investor acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, and businessman, with more than 30 years of investment experience in AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US global capital markets and in resource and industrial projects and was an Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times early investor in GeoPark. Mr. Papadimitriou is currently CEO of General an Executive Committee Member, and the Audit Committee Chair of the Oriental Investments S.A., the Investment Manager of the Cavenham Group University of Maryland at College Park Board of Trustees. Mr. Bedingfield of Funds. Previously, he was CEO of Cavamont Geneva. During his tenure served on the National Executive Board (1995 to 2003) and National Advisory at the Cavamont group, Mr. Papadimitriou was responsible for Treasury Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield Management, the Private Equity Portfolio as well as representing the group has also served as Board Member and Chairman of the Audit Committee of on the Boards of associated companies including investments in the oil and NYSE-listed Science Applications International Corp (SAIC). gas, mining, real estate and gaming sectors (including Basic Petroleum, a Pedro E. Aylwin Chiorrini has served as a member of our board of directors of Diorasis International, a company focusing on investments in Greece and since July 2013 and as our Director of Legal and Governance since April 2011. the broader Balkans and he also chairs the Greek Language School of Geneva From 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance and Lausanne. Mr Papadimitriou holds an Economics and Finance degree and and legal matters. Mr. Aylwin holds a degree in law from the Universidad de a post-graduate Diploma in European Studies from Geneva University. Nasdaq-listed Guatemalan oil and gas company). He is also founding partner Chile and an LLM from the University of Notre Dame. Mr. Aylwin has extensive experience in the natural resources sector. Mr. Aylwin is also a partner at the Senior management law firm Aylwin, Mendoza, Luksic, Valencia Abogados in Santiago, Chile, where Our senior management is responsible for the management and he represented mining, chemical and oil and gas companies in numerous representation of our company. The table below sets forth certain information transactions. From 2006 until 2011, he served as Lead Manager and General concerning our senior management. All ages are as of March 31, 2019. Counsel at BHP Billiton, Base Metals, where he was in charge of legal and corporate governance matters on BHP Billiton’s projects, operations and natural resource assets in South America, North America, Asia, Africa and Australia. Jamie B. Coulter is a well-respected businessman, who has spearheaded the growth of a variety of businesses in diverse sectors. He holds a business degree from Wichita State University and is a graduate of the Stanford University Executive Program. Mr. Coulter currently serves as Managing Member of Coulter Enterprises LLC., a private investment firm. Mr. Coulter has been an investor in GeoPark since 2006. Mr. Coulter has more than 46 years of experience in the food retail and restaurant business, serving as Chief Executive Officer of Lone Star Steakhouse & Saloon and having developed and operated Pizza Hut and Kentucky Fried Chicken restaurants. Mr. Coulter is a former Restaurants & Institutions CEO of the year. Mr. Coulter has operating and investment experience in the oil and gas business, including the founding of Sunburst Exploration, a US upstream oil and gas company that he built throughout the 1980s and sold in 1994. Mr. Coulter also has been GeoPark 129 Name James F. Park Andrés Ocampo Position Chief Executive Officer and Director Chief Financial Officer Pedro E. Aylwin Chiorrini Director, Director of Legal and Governance, and Corporate Secretary Augusto Zubillaga Rodolfo Martín Terrado Alberto Matamoros Livia Valverde Adriana La Rotta Barbara Bruce Marcela Vaca Carlos Murut Salvador Minniti Horacio Fontana Agustina Wisky Guillermo Portnoi Stacy Steimel Chief Operating Officer Director of Operations Director for Argentina and Chile Director for Brazil Director of Connections Director for Peru Director for Colombia Director of Reserves and Development Director of Exploration Director of Drilling and Workover Director of Capacities and Culture Director of New Business Director of Shareholder Value Age At the Company since 63 41 59 49 44 47 41 56 62 50 62 64 61 42 43 59 2002 2010 2003 2006 2018 2014 2013 2018 2017 2012 2006 2007 2008 2002 2006 2017 Biographical information of the members of our senior management is set on electrical submersible pump optimization, corrosion control, water forth below. Unless otherwise indicated, the current business addresses for handling and intelligent production systems. members of our senior management is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile. Rodolfo Martín Terrado joined GeoPark in August 2018. Mr. Terrado has over 20 years of experience in asset development and operations. Prior Andrés Ocampo has served as our Chief Financial Officer since November to joining GeoPark, Mr. Terrado worked for Petrolera Argentina San 2013. He previously served as our Director of Growth and Capital (from Jorge and Chevron in different international operations, including in January 2011 through October 2013), and has been with our company since Argentina, the United States and Venezuela. Mr. Terrado previously led July 2010. Mr. Ocampo graduated with a degree in Economics from the heavy oil operations in Venezuela assets and his prior responsibilities Universidad Católica Argentina. He has more than 16 years of experience in include waterflooding, CO2 flooding and unconventionals. Mr. Terrado business and finance. Before joining our company, Mr. Ocampo worked at holds a Petroleum Engineering degree from ITBA and an MBA from IAE in Citigroup and served as Vice President Oil & Gas and Soft Commodities at Argentina. Crédit Agricole Corporate & Investment Bank. Alberto Matamoros has been our Director for Argentina and Chile since Augusto Zubillaga has served as our Chief Operating Officer since May March 2016 and Director for Chile since January 2015. He is an industrial 2015. He previously served in other management positions throughout engineer and has an MBA, with more than 20 years of experience in the Oil the Company including as Operations Director, Argentina Director and & Gas industry. He started his career in the Argentinian oil company ASTRA, Production Director. He previously served as our Production Director. He is as a Production Engineer of La Ventana-Vizcacheras Block in the Province a petroleum engineer with more than 23 years of experience in production, of Mendoza (1997-2000). He then joined Chevron, where he worked as engineering, well completions, corrosion control, reservoir management a Production Engineer in El Trapial Block in the Province of Neuquén for and field development. He has a degree in petroleum engineering from three years. Later, he became a Field Engineering Manager, also for three the Instituto Tecnológico de Buenos Aires. Prior to joining our company, years, in Buenos Aires, and then moved to Kern County, California, to lead Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron the production team. His experience in Chevron enabled him to manage San Jorge S.A. At Chevron San Jorge S.A., he led multi-disciplinary teams different technical and administrative teams, designing and executing focused on improving production, costs and safety, and was the leader of working plans focused in the optimization of resources. In 2014, he joined the Asset Development Team, which was responsible for creating the field GeoPark to be part of the Corporate Operation team before being selected development plan and estimating and auditing the oil and gas reserves of as the new Director for Chile. Matamoros holds a degree in Industrial the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron San Engineering from the Universidad Nacional del Sur and an MBA in IAE, from Jorge S.A. team that was responsible for identifying business opportunities the Business School of Universidad Austral of Buenos Aires, Argentina. and working with the head office on the establishment of best business practices. He has authored several industry papers, including papers Livia Valverde has been our Director for Brazil since 2018. Mrs. Valverde 130 GeoPark 20F previously served as our Legal Manager and has been with us since 2013. previously served as our Development Manager. Mr. Murut holds a master’s She holds a law degree from the Catholic University of Salvador in Brazil degree in petroleum geology from the University of Buenos Aires where he and holds a Master´s Degree in Corporate Law from the Brazilian Institute also undertook postgraduate studies in reservoir engineering, specializing of Capital Markets – IBMEC and a MBA in Environmental Management from in field exploitation. He also completed a Business Management the Getulio Vargas Foundation. Mrs. Valverde has more than 17 years of Development Program at Austral University. Mr. Murut has over 40 years of experience in the oil and gas industry, and previously served as manager at experience working for international and major oil companies, including several international E&P companies based in Rio de Janeiro, where she was YPF S.A., Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San responsible for legal, environmental and regulatory matters. Jorge S.A. Adriana La Rotta has been our Director of Connections since November Salvador Minniti has been our Director of Exploration since January 2012. 2018. Ms. La Rotta is a communications professional and award-winning He previously served as our Exploration Manager. He holds a bachelor journalist with broad experience in Latin America, Asia, and the United degree in geology from National University of La Plata and has a graduate States. For over six years she led the media relations strategy for the degree from the Argentine Oil and Gas Institute in oil geology. Mr. Minniti Americas Society/Council of the Americas, a New York-headquartered has over 35 years of experience in oil exploration and has worked with YPF business organization whose members are international corporations S.A., Petrolera Argentina San Jorge S.A. and Chevron Argentina. representing a broad range of industries. Previously she was a TV reporter and anchor in her native Colombia and worked as a foreign correspondent Horacio Fontana has been our Corporate Drilling Manager since March in Brazil, the United States, Japan, and Hong Kong. She holds a BA in 2012. He previously served as our Engineer Manager. He holds a degree in Journalism from Colombia’s Universidad Javeriana and a certificate in NGO civil engineering from Rosario National University and is also a graduate Management from Temple University-Japan. from the Argentine Oil and Gas Institute, National University of Buenos Aires, with a specialty in oilfield exploitation and an extensive background Barbara Bruce has been our Director for Peru since June 2017. Ms. Bruce in drilling operations. He has recently taken part in a Management holds a degree in Geology from the Universidad Nacional de Ingeniería, Development Program at IAE Business School of Austral University. Mr. Lima, Peru, a Master’s degree in Reservoirs from Colorado School of Mines, Fontana has over 31 years of drilling experience in major Argentine USA and an MBA from Universidad Adolfo Ibañez, USA/Chile. Before joining companies such as YPF S.A., Petrolera Argentina San Jorge and Chevron. GeoPark, she previously worked with Occidental Petroleum in different international operations, including in the Caño Limon field in Colombia Agustina Wisky has worked with our Company since it was founded in and the Dhurnal and Bhangali gas fields in Pakistan. Ms. Bruce later worked November 2002. She is currently our Director of Capacities and Culture and as deputy President of an offshore operation by Petrotech Peruana, joined she previously has served in other management positions throughout the Hunt Oil and as General Manager of Peru LNG, leading the construction and Company as Director of People and Director of Business Management. Mrs. startup of operation of Peru´s first LNG plant and managed the exploration Wisky is a public accountant, and also holds a degree in human resources venture of Hunt Oil in Madre de Dios, Peru. from the Universidad Austral—IAE. She has 19 years of experience in the oil industry. Before joining our Company, Mrs. Wisky worked at AES Gener and Marcela Vaca has been our Director for Colombia since August 2012. Ms. PricewaterhouseCoopers. Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá, Colombia, a Master’s Degree in commercial law from the same university Guillermo Portnoi has worked with our Company since June 2006 and has and an LLM from Georgetown University. She has served in the legal been our Director of Business Management since May 2015 until December departments of a number of companies in Colombia, including Empresa 2016 and is currently our Director of New Business. Previously, he also Colombiana de Carbon Ltda (which later merged with INGEOMINAS), and served as our Director of Administration and Finance. Mr. Portnoi is a public from 2000 to 2003, she served as Legal and Administrative Manager at GHK accountant and holds an MBA from Universidad Austral—IAE. He has more Company Colombia. Prior to joining our Company in 2012, Ms. Vaca served than 14 years of experience in the oil industry. Before joining our Company, for nine years as General Manager of the Hupecol Group where she was Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers, responsible for supervising all areas of the Company as well as managing where he counted several major oil companies as his clients. relationships with Ecopetrol, ANH, the Colombian Ministry of Mines and Energy, the Colombian Ministry of Environment and other governmental Stacy Steimel joined GeoPark in February 2017 as our Shareholder Value agencies. At the Hupecol Group, Ms. Vaca was also involved in the Director. Mrs. Steimel has more than 20 years of experience in the financial structuring of the Hupecol Group’s asset development and sales strategy. sector as Fund Manager and subsequently as regional CEO for PineBridge Investments, ex-AIG Investments in Latin America. Before AIG, Mrs. Steimel Carlos Murut has been our Director of Development since January 2012. He held positions in the US Treasury Department and at the InterAmerican GeoPark 131 Development Bank. She holds an MBA from the Pontificia Universidad Bonus payments above were approved by the Compensation Committee on Católica de Chile, an MA in Latin American Studies from the University of May 7, 2018 and reflect discretionary cash bonus payment made based on Texas at Austin and a BA from the College of William and Mary. our performance in 2017. Additionally, Mr. Park´s compensation includes an B. Compensation annual equity award with an aggregate value equal to one year of base salary, based on the previous year’s average share price, and with a three year vesting Senior management and director compensation period. Due to the foregoing, on May 7, 2018, Mr. Park was awarded 104,439 For the year ended December 31, 2018, we accrued or paid approximately shares based on the 2017 average share price, and; on March 6, 2019, Mr. Park US$4.6 million, in the aggregate, to the members of our board of directors was awarded 52,049 shares, based on the 2018 average share price. (including our executive directors) for their services in all capacities. During this same period, we accrued or paid approximately US$11.0 million, in Non-Executive Director Contracts the aggregate, to the members of our senior management (excluding our The current annual fees paid to our non-executive Directors correspond to executive directors) for their services in all capacities. An amount of US$0.8 US$80,000 to be settled in cash and US$100,000 to be settled in stock, paid million corresponds to the accrual or payment for discretionary bonus quarterly in equal installments. In the event that a non-executive Director cash payments granted to the Company’s executive directors based on the serves as Chairman of any Board Committees, an additional annual fee Company’s performance in 2018. Gerald E. O’Shaughnessy, James F. Park and of US$20,000 applies. A Director who serves as a member of any Board Pedro E. Aylwin Chiorrini are our executive directors. Committees receives an annual fee of US$10,000. Total payment due shall Executive Director Contracts be calculated on an aggregate basis for Directors serving in more than one Committee. The Chairman fee is not added to the member’s fee while serving It is our current policy that executive directors enter into indefinite term for the same Committee. Payments of Chairmen and Committee members’ contracts with the Company that may be terminated at any time by either fees are made quarterly in arrears and settled in cash only. party subject to certain notice requirements. The following chart summarizes payments made to our non-executive Gerald E. O’Shaughnessy has entered into a service contract with the directors for the year ended December 31, 2018. Company to act as Chairman at an annual salary of US$400,000. James F. Park has entered into a service contract with the Company to act as Chief Non-Executive Directors’ Executive Officer at an annual salary of US$800,000. They each also received equity awards described below under “Equity Incentive Compensation.” Our agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that restrict them, for a period of 12 months following termination of employment, from soliciting senior employees of the Company and, for a period of six months following a termination of employment, from competing with the Non-Executive Director Juan Cristóbal Pavez (2) Carlos Gulisano (3) Robert Bedingfield (4) Constantine Papadimitriou (5) Jamie B. Coulter (6) Fees in US$ 110,000 110,000 110,000 45,000 75,000 Fees paid in Common Shares (1) 7,596 7,596 7,596 2,761 7,596 Company. Pedro E. Aylwin Chiorrini, who was appointed as an executive director in July 2013, has entered into a service contract with the Company to act as Director of Legal and Governance, and as such has decided to forego his director fees. He received in 2018 a salary of US$0.4 million and bonus of US$0.1 million for his services as a member of senior management. The following chart summarizes payments made to our executive directors for the year ended December 31, 2018: (1) The numbers in this column are equal to 33,145 Common Shares (which amount equals to US$450,000). (2) Compensation Committee Chairman and Member of Audit Committee. (3) Technical Committee Chairman and Member of Compensation Committee. (4) Audit Committee Chairman and Member of Nomination Committee. (5) Member of the Audit Committee, appointed on March 6, 2019. (6) Member of the Compensation Committee. Cash Payment in Pension and retirement benefits payment shares We do not maintain any defined benefit pension plans or any other retirement Gerald E. O’Shaughnessy Executive Directors’ Fees US$400,000 Bonus — programs for our employees or directors. Bonus — Equity Incentive Compensation James F. Park US$800,000 US$695,506 US$800,000 Pedro E. Aylwin Chiorrini US$26,000 — — Performance-Based Employee Long-Term Incentive Program 132 GeoPark 20F Given the expiration of our Stock Awards Plan on November 3, 2018, in Our executive directors, senior management and employees who have December 2018, we adopted the 2018 Equity Incentive Plan (the “Plan”) to received option awards or common share awards under the Stock Awards motivate and reward those participating employees, directors, consultants Plan authorize the Company to deposit any common shares they have and advisors of our Group to perform at the highest level and to further the received under this plan in our Employee Benefit Trust (“EBT”). The EBT is best interests of the Company and our shareholders. The Plan is designed as held to facilitate holdings and dispositions of those common shares by the an omnibus plan, with a 10-year term, and encompasses all forms of equity participants thereof. Under the terms of the EBT, each participant is entitled incentive that the Company may wish to implement throughout such term. to receive any dividends we may pay which correspond to their common The maximum number of shares available for issuance under the Plan is shares held by the trust, according to instructions sent by the Company to the 5,000,000 shares. Stock Awards Plan trust administrator. The trust provides that Mr. James F. Park is entitled to vote all the common shares held in the trust. Although Mr. Park has voting rights with respect to all the common shares held on the trust, Mr. Park disclaims Under the Stock Awards Plan, the board of directors, or its designee, could beneficial ownership over the shares in the trust as described under “-E. Share award options or stock awards. An option confers the right to acquire a Ownership.” specified number of common shares of the Company at an exercise price equal to the par value of the common shares subject to such an option. A Value Creation Plan performance share confers a conditional right to acquire a specified number of On December 10, 2015, our Board of Directors approved a renewal of the common shares for zero or nominal consideration, subject to the achievement VCP for a new period of three years, with new awards granted on January 1, of performance conditions and other vesting terms. 2016. Under the VCP, if as of December 31, 2018, our share price has increased On December 17, 2014, we registered 3,435,600 shares with the U.S. SEC for management) will receive awards with an aggregate value equal to 10% of shares to be issued under the Stock Awards Plan. On December 12, 2018 the excess above the market capitalization threshold (12%) generated by this we registered an additional 4,313,645 shares to be issued under such plan. share price (assuming that our share capital remained at the same level as The following table sets forth the common share awards granted to our applicable at the time of establishment of the VCP: 59,535,614 shares). The executive directors, management and employees under the Stock Awards Plan VCP Performance Goals were satisfied and awards thereunder have therefore commencing in 2008 through March 31, 2019. vested. As per the terms of the VCP, (i) on January 2 2019, 50% of the vested by 12% per year according to the plan conditions, VCP participants (key Number of underlying common shares outstanding 817,600(1) 478,000(1) 379,500 490,000 1,619,105 (3) 104,439 (4) 200,000 (3) 52,049 (4) Grant date 12/15/2010 12/15/2011 12/15/2012 12/31/2014 06/30/2016 05/07/2018 05/31/2018 03/06/2019 awards, representing 1,488,390 shares, was issued to participants (including 439,075 issued to directors involved in the performance of the Company), and (ii) in January 2020, the remaining 50% of the awards will be issued. For further Vesting date Expiration date details, see Note 30 to our consolidated financial statements. On January 12/15/2014 12/15/2015 12/15/2016 12/31/2017 06/30/2019 05/07/2021 06/30/2019 03/06/2022 12/15/2020 2, 2019, James F. Park received 193,491 shares; Mr. O’Shaughnessy received 12/15/2021 89,303 shares; Mr. Aylwin received 111,629 shares and Mr. Gulisano received 12/15/2022 44,652 shares due to the VCP issuance. 12/31/2022 06/30/2026 Non-Executive Director Plan 03/15/2022 In August 2014, our Board of Directors adopted the Non-Executive Director 06/30/2026 Plan in order to grant shares to non-executive directors as part of their 03/15/2023 compensation program for serving as directors. The Non-Executive Director (1) Pedro E. Aylwin Chiorrini holds 40,000 shares of the 2008 award, 25,000 shares of the 2010 award and 12,000 shares of the 2011 award. (2) James F. Park received 450,000 shares of such awards, and Gerald E. O’Shaughnessy received 270,000 shares of such awards. (3) Vesting of these common share awards was subject to the achievement of certain minimum financial and operational targets during a performance period ran from 2016 to 2018. (4) James F. Park received these awards on May 5, 2018 and March 6, 2018, respectively, as part of his long-term equity incentive compensation. For further details, please see item 6.B. Plan was amended and restated in October 2016, when additional 1,000,000 shares were registered as the maximum number of shares available to be issued under this plan. In accordance with the resolutions adopted by our board of directors on May 20, 2014, our non-executive directors are paid their quarterly fees in the form of equity awards granted under the Non-Executive Director Plan. Under the Non-Executive Director Plan, the compensation committee may award common shares, restricted share units and other share- based awards that may be denominated or payable in common shares or factors that influence the value of common shares. Potential dilution resulting from Equity Incentive Compensation Plans In accordance with the equity awards granted by the Company under its stock GeoPark 133 awards plan, as of December 31, 2018 there were approximately five million relating to our performance; (c) assessing the independence, objectivity and five hundred thousand outstanding shares that had been awarded but and effectiveness of our external auditors; (d) making recommendations for which had not yet vested, representing approximately 9% of the total issued the appointment, re-appointment and removal of our external auditors and share capital as of that date. C. Board practices Overview approving their remuneration and terms of engagement; (e) implementing and monitoring policy on the engagement of external auditors supplying non-audit services to us; (f ) obtaining, at our expense, outside legal or other professional advice on any matters within its terms of reference and securing the attendance at its meetings of outsiders with relevant experience and Our Board of Directors is responsible for establishing our listed company expertise if it considers it necessary; and (g) reviewing our arrangements goals, ensuring that the necessary resources are in place to achieve for our employees to raise concerns about possible wrongdoing in financial these goals and reviewing our management and financial performance. reporting or other matters and the procedures for handling such allegations, Our board of directors directs and monitors the company in accordance and ensuring that these arrangements allow proportionate and independent with a framework of controls, which enable risks to be assessed and investigation of such matters and appropriate follow-up action. managed through clear procedures, lines of responsibility and delegated authority. Our board of directors also has responsibility for establishing Compensation Committee our core values and standards of business conduct and for ensuring that The Compensation Committee is composed of three directors. The current these, together with our obligations to our shareholders, are understood members of the compensation committee are Mr. Juan Cristóbal Pavez throughout the company. (who serves as Chairman of the committee), Jamie B. Coulter and Mr. Carlos Board composition Gulisano. Our bye-laws and board resolutions provide that the board of directors consist The Compensation Committee meets at least twice a year, and its specific of a minimum of three and a maximum of nine members. All of our directors responsibilities include: (a) reviewing and recommending to the board were elected at our annual shareholders’ meeting held on July 27, 2018. Their of directors the remuneration policy for the Chief Executive Officer, term expires on the date of our next annual shareholders’ meeting, to be held the Chairman, our executive directors and other members of executive in 2019. The board of directors meets at least on a quarterly basis. management; (b) reviewing the performance of our executive directors Committees of our board of directors and members of executive management; and (c) reviewing all incentive compensation plans, equity-based plans, and all modifications to such Our board of directors has established an Audit Committee, a Compensation plans as well as administering and granting awards under all such plans and Committee, a Nomination Committee, a Technical Committee and a Disclosure approving plan payouts; and (d) reviewing and making recommendations Committee. The composition and responsibilities of each committee are to the Board with respect to the adoption or modification of executive described below. Members serve on the Audit Committee for a period of three officer and director share ownership guidelines and monitor compliance years. For the Nomination Committee, members serve for a period of one with any adopted share ownership guidelines. year. For the Compensation Committee, members serve for the same period as their board term. For the Technical Committee and Disclosures Committee, Nomination Committee members serve on these committees until their resignation or until otherwise The Nomination Committee is composed of four directors. The members of determined by our board of directors. In the future, our board of directors may the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. James F. establish other committees to assist with its responsibilities. Park, Mr. Robert Bedingfield and Mr. Pedro E. Aylwin Chiorrini (who serves as Chairman of the committee). Audit Committee The Audit Committee is composed of three directors. As of 31 December 2018, The Nomination Committee meets at least twice a year and its responsibilities the members of the Audit Committee were Mr. Juan Cristóbal Pavez and Mr. include: (a) reviewing the structure, size and composition of the board of Robert Bedingfield (who currently serves as Chairman of the committee). On directors and making recommendations to the board of directors in respect of March 6, 2019 we appointed Constantine Papadimitriou to fill the vacancy. any required changes; (b) identifying, nominating and submitting for approval We have determined that Mr. Juan Cristóbal Pavez, Robert Bedingfield and by the board of directors candidates to fill vacancies on the board of directors Constantine Papadimitriou are independent, as such term is defined under as and when they arise; (c) making recommendations to the board of directors SEC rules applicable to foreign private issuers. with respect to the membership of the Audit Committee and Compensation The Audit Committee’s responsibilities include: (a) approving our financial respect to the appointment of any director or executive officer or other officer statements; (b) reviewing financial statements and formal announcements other than the position of the Chairman and Chief Executive Officer and (d) Committee in consultation with the chairman of each committee, and with succession planning for directors and senior executives. 134 GeoPark 20F Major shareholders and related party transactions Technical Committee E. Share ownership The Technical Committee is composed of three directors along with the As of March 15, 2019, members of our board of directors and our senior Chief Operating Officer. The members of the Technical Committee are Mr. management held as a group 21,769,498 of our common shares and 35.5% of Carlos Gulisano (who serves as Chairman of the committee), Mr. Gerald our outstanding share capital. O´Shaughnessy, Mr. James F. Park and Mr. Augusto Zubillaga. The Technical Committee’s responsibilities include: (a) overseeing the of directors and senior management as of March 15, 2019. The following table shows the share ownership of each member of our board technical studies and evaluations of the Company’s properties and proposals to acquire new properties and/or relinquish existing ones as well as reviewing project plans; (b) reviewing the Annual Reserve Report, the Company’s environmental programs and their effectiveness and the Company’s health and safety program and its effectiveness; and (c) providing a forum for ideas and solutions for the key technical people within the Company. Disclosure Committee (1) Shareholder James F. Park(1) Gerald E. O’Shaughnessy(2) Juan Cristóbal Pavez(3) Jamie B. Coulter Pedro E. Aylwin Chiorrini The Disclosure Committee is composed of Mr. James F. Park, Mr. Andrés Carlos Gulisano Ocampo, and certain other officers or managers per request. The Disclosure Committee’s responsibilities include (a) review and approval of Robert Bedingfield Constantine Papadimitriou(4) Augusto Zubillaga filings with the SEC and press releases, (b) review of presentations to analysts, Alberto Matamoros investors and rating agencies and (c) establishment of disclosure controls and Marcela Vaca procedures. Liability insurance Barbara Bruce Carlos Murut Salvador Minniti We maintain liability insurance coverage for all of our directors and officers, Stacy Steimel the level of which is reviewed annually. D. Employees Horacio Fontana Agustina Wisky Guillermo Portnoi Livia Valverde As of December 31, 2018, we had 457 employees, representing an increase of Adriana La Rotta 13% from December 31, 2017. Rodolfo Martín Terrado Andrés Ocampo Common Percentage of outstanding shares 8,084,760 7,032,619 2,970,725 1,524,150 332,488 204,542 94,058 22,761 * * * * * * * * * * * * * * common shares 13.2% 11.5% 4.8% 2.5% * * * * * * * * * * * * * * * * * * The following table sets forth a breakdown of our employees by geographic Sub-total senior management segment for the periods indicated. ownership of less than 1% Total 1,503,395 21,769,498 2.5% 35.5% Colombia Chile Brazil Argentina Peru Corporate Total Year ended December 31, 2018 178 100 12 137 28 2 457 2017 180 102 12 92 19 - 2016 * Indicates ownership of less than 1% of outstanding common shares. 146 102 10 77 10 - (1) Held directly and indirectly by Energy Holdings, LLC, which is controlled by James F. Park, a member of our board of directors. The number of common shares held by Mr. Park does not reflect 1,573,800 of common shares held as of March 15, 2019 in the employee benefit trust described under “Item 6. Directors, Senior Management and Employees—B. 405 345 Compensation— Stock Awards Plan.” Although Mr. Park has voting rights with respect to all the common shares held on the trust, Mr. Park disclaims From time to time, we also utilize the services of independent contractors beneficial ownership over 1,573,800 of these shares. 1,073,201 of Mr. Park’s to perform various field and other services as needed. As of December 31, 2018, 58 of our employees were represented by labor unions or covered by collective bargaining agreements. We believe that relations with our shares have been pledged pursuant to lending arrangements. (2) Held directly and indirectly through GP Investments LLP, GPK Holdings LLC, The Globe Resources Group, Inc. and other investment vehicles. employees are satisfactory. GeoPark 135 5,350,000 of these common shares have been pledged pursuant to lending We have entered into the following transactions with related parties: arrangements. (3) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 92,921 common shares held by him personally. (4) Due to Constantine Papadimitriou´s position as CEO of General Oriental Investments S.A., he may be deemed to have beneficial ownership over an LGI Chile Shareholders’ Agreements In November 2018, we acquired all of LGI’s equity interest in GeoPark’s Chilean and Colombian subsidiaries. additional 2,082,605 shares held by Cavenham Group of Funds. Pursuant to the sale and purchase agreement entered into on November 28, 2018 (the “LGI Termination Agreement”), we agreed to pay LGI a total ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS consideration of up to US$126 million for its entire equity interest in Geopark A. Major shareholders Chile, Geopark TdF and Geopark Colombia Coöperatie U.A. The acquisition price includes a fixed payment of US$81 million paid at closing, plus two The following table presents the beneficial ownership of our common shares equal installments of US$15 million each, to be paid in June 2019 and June as of March 15, 2019, except for certain shareholders whose last public 2020, respectively, and three contingent payments of US$5 million each, available data is as of December 31, 2018, as noted below: which could accrue over the next three years, subject to certain production Common Percentage of outstanding LGI Termination Agreement we have become sole shareholder of the entities thresholds being exceeded in the Llanos 34 Block. As a consequence of the Shareholder James F. Park(1) Gerald E. O’Shaughnessy(2) Manchester Financial Group, L.P.(3) Compass Group LLC(4) Renaissance Technologies Holdings Corporation(5) Other shareholders Total shares 8,084,760 7,032,619 5,246,296 3,899,301 3,527,000 33,525,273 61,315,249 common shares referred to above. The LGI Chile Shareholders’ Agreement, the LGI Colombia Shareholders’ Agreement and the LGI line credit, each described in our annual report on the 20-F for the fiscal year ended December 31, 2017 were also terminated. 13.2% 11.5% 8.6% 6.4% Executive Directors’ Service Agreements 5.8% We have entered into service contracts with certain of our executive 54.5% directors. See “Item 6. Directors, Senior Management and Employees—B. 100.0% Compensation—Executive compensation—Director Contracts.” (1) See Footnote (1) to the share ownership table included in Item 6.E above. (2) See Footnote (2) to the share ownership table included in Item 6.E above. (3) Held directly and indirectly through Manchester Financial Group, L.P., Manchester Financial Group, Inc., Douglas F. Manchester and Papa Doug Trust u/t/d/ January 11, 2010. This information is as of December 31, 2018. (4) The information set forth above and listed in the table is as of December 31, 2018 and based solely on the disclosure set forth in Compass Group LLC’s most recent Schedule 13F filed with the SEC on February 6, 2019. (5) Held directly and indirectly through Renaissance Technologies LLC and Renaissance Technologies Holdings Corporation. This information is as of December 31, 2018 and based solely on the disclosure set forth in the most For further information relating to our related party transactions and balances outstanding as of December 31, 2018, 2017 and 2016, please see Note 33 to our Consolidated Financial Statements. C. Interests of Experts and Counsel Not applicable. ITEM 8. FINANCIAL INFORMATION A. Consolidated statements and other financial information recent Schedule 13G filed with the SEC on February 12, 2019. Financial statements See “Item 18. Financial Statements,” which contains our audited financial Principal shareholders do not have any different or special voting rights in statements prepared in accordance with IFRS. comparison to any other common shareholder. Legal proceedings According to our transfer agent, as of March 15, 2019, we had 19 registered From time to time, we may be subject to various lawsuits, claims and shareholders, out of which 6 are registered as U.S. shareholders. Since some proceedings that arise in the normal course of business, including of the shares are held by nominees, the number of shareholders may not be employment, commercial, environmental, safety and health matters. For representative of the number of beneficial owners. example, from time to time, we receive notice of environmental, health and B. Related party transactions 136 GeoPark 20F safety violations. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position and results of operations. In Brazil, GeoPark Brasil is a party to a class action filed by the Federal consequently, your only opportunity to achieve a return on your investment Prosecutor’s Office regarding a concession agreement of exploratory Block is if the price of our stock appreciates” and “—We are a holding company PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil dependent upon dividends from our subsidiaries, which may be limited by and gas bidding round held in November 2013. The Brazilian Federal Court law and by contract from making distributions to us, which would affect our issued an injunction against the ANP and GeoPark Brasil in December 2013 financial condition, including the ability to pay dividends on the common that prohibited GeoPark Brasil’s execution of the concession agreement shares,” as well as “Item 10. Additional Information—B. Memorandum of until the ANP conducted studies on whether drilling for unconventional association and bye-laws.” 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 B. Significant changes agreement, which included a clause prohibiting GeoPark Brasil from conducting unconventional exploration activity in the area. Despite the A discussion of the significant changes in our business can be found under clause containing the prohibition, the judge in the case concluded that the “Item 4. Information on the Company—B. Business Overview.” concession agreement should not be executed. Thus, GeoPark Brasil requested that the ANP comply with the decision and annul the concession agreement, ITEM 9. THE OFFER AND LISTING 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 A. Offering and listing details right to the block. Not applicable. Dividends and dividend policy B. Plan of distribution Holders of common shares will be entitled to receive dividends, if any, paid on Not applicable. the common shares. C. Markets We have never declared or paid any cash dividends on our common shares. Our common shares have been listed on the NYSE under the symbol “GPRK” We intend to retain all of our future earnings, if any, generated by our since February 7, 2014. operations for the development and growth of our business. Accordingly, we do not expect to pay cash dividends on our common shares in the foreseeable D. Selling shareholders future. Because we are a holding company with no direct operations, we will Not applicable. only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries. The terms of our indebtedness may restrict E. Dilution us from paying dividends. We have recorded accumulated losses amounting Not applicable. to US$206.7 million as of December 31, 2018, which further limits our ability to pay dividends in the foreseeable future. F. Expenses of the issue Not applicable. Under the Bermuda Companies Act, we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the ITEM 10. ADDITIONAL INFORMATION 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 A. Share capital do not presently have any reasonable grounds for believing that, if we were Not applicable. to declare or pay a dividend on our common shares outstanding, we would thereafter be unable to pay our liabilities as they became due or that the B. Memorandum of association and bye-laws realizable value of our assets would thereafter be less than our liabilities. The following description of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference Additionally, any decision to pay dividends in the future, and the amount to, all of the provisions of our memorandum of association and bye-laws. 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 General operations, financial condition, cash requirements, prospects and other We are an exempted company with limited liability incorporated under the laws factors. See “Item 3. Key Information—D. Risk factors—Risks related to our of Bermuda with registration number 33273 from the Registrar of Companies. common shares—We have never declared or paid, and do not intend to The rights of our shareholders will be governed by Bermuda law and by our pay in the foreseeable future, cash dividends on our common shares, and, memorandum of association and bye-laws. Bermuda company law differs GeoPark 137 in some material respects from the laws generally applicable to Delaware fewer than three directors. The maximum number of directors currently corporations. Below is a summary of some of those material differences. allowed is nine directors and our board of directors currently consists of Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and to our shareholders. Election and removal of directors seven directors. Share capital and bye-laws Our bye-laws provide that our directors shall hold office for such term as the shareholders shall determine or, in the absence of such determination, Our share capital consists of common shares only. Our authorized share capital until the next annual general meeting or until their successors are elected consists of 5,171,949,000 common shares of par value US$0.001 per share. or appointed or their office is otherwise vacated. Directors whose term has As of the date of this annual report, there are 60,606,787 common shares expired may offer themselves for re-election at each election of the directors. outstanding. All of our issued and outstanding common shares are fully paid and non-assessable. We also have an employee incentive program, pursuant to Under our bye-laws, a director may be removed by a resolution adopted by which we have granted share awards to our senior management and certain 65% or more of the votes cast by shareholders who (being entitled to do key employees. See “Item 6. Directors, Senior Management and Employees.” so) vote in person or by proxy at any general meeting of the shareholders According to our bye-laws, if our share capital is divided into different classes purpose of removing the director, containing a statement of the intention of shares, the rights attached to any class (unless otherwise provided by the to do so, must be served on such director not less than 14 days before the in accordance with the provisions of our bye-laws. Notice convened for the terms of issue of the shares of that class) may, whether or not the Company meeting. is being wound-up, be varied with the consent in writing of the holders of at least two-thirds of the issued shares of that class or with the sanction of a Any vacancy created by the removal of a director at a special general meeting resolution passed by a majority of the votes cast at a separate general meeting may be filled at that meeting by the election of another director in his or her of the holders of the shares of the class at which meeting the necessary place or, in the absence of any such election, by the board of directors. Any quorum shall be two persons at least, in person or by proxy, holding or other vacancy, including a newly created directorship, may be filled by our representing one-third of the issued shares of the class. The rights conferred board of directors. upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise expressly provided by the terms of issue of Proceedings of board of directors the shares of that class, be deemed to be varied by the creation or issue of Our bye-laws provide that our business shall be managed by or under the further shares ranking pari passu therewith. direction of our board of directors. Our board of directors may act by the Our bye-laws give our board of directors the power to issue any unissued a quorum is present. The quorum necessary for the transaction of business shares of the company on such terms and conditions as it may determine, at meetings of the board of directors shall be the presence of a majority subject to the terms of the bye-laws and any resolution of the shareholders to of the board of directors from time to time. Our bye-laws also provide that affirmative vote of a majority of the directors present at a meeting at which the contrary. Common shares resolutions unanimously signed by all directors are valid as if they had been passed at a meeting of the board duly called and constituted. Holders of our common shares are entitled to one vote per share on all Duties of directors matters submitted to a vote of holders of common shares. Subject to Under Bermuda common law, members of a board of directors owe a fiduciary preferences that may be applicable to any issued and outstanding preference duty to the Company to act in good faith in their dealings with or on behalf shares, holders of common shares are entitled to receive such dividends, of the company, and to exercise their powers and fulfill the duties of their if any, as may be declared from time to time by our board of directors office honestly. This duty has the following essential elements: (1) a duty to out of funds legally available for dividend payments. Holders of common act in good faith in the best interests of the company; (2) a duty not to make shares have no redemption, sinking fund, conversion, exchange or other a personal profit from opportunities that arise from the office of director; (3) subscription rights. In the event of our liquidation, the holders of common a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the shares are entitled to share equally and ratably in our assets, if any, remaining purpose for which such powers were intended. The Bermuda Companies after the payment of all of our debts and liabilities, subject to any liquidation Act also imposes a duty on directors of a Bermuda company, to act honestly preference on any outstanding preference shares. and in good faith, with a view to the best interests of the company, and to Board composition exercise the care, diligence and skill that a reasonably prudent person would Our bye-laws provide that our board of directors will determine the exercise in comparable circumstances. In addition, the Bermuda Companies maximum size of the board, provided that it shall be not be composed of Act imposes various duties on directors with respect to certain matters of management and administration of the company. 138 GeoPark 20F The Bermuda Companies Act provides that in any proceedings for negligence, Indemnification of directors and officers default, breach of duty or breach of trust against any director, if it appears Bermuda law provides generally that a Bermuda company may indemnify its to a court that such officer is or may be liable in respect of the negligence, directors and officers against any loss arising from or liability which by virtue default, breach of duty or breach of trust, but that he has acted honestly of any rule of law would otherwise be imposed on them in respect of any and reasonably, and that, having regard to all the circumstances of the case, negligence, default, breach of duty or breach of trust except in cases where including those connected with his appointment, he ought fairly to be such liability arises from fraud or dishonesty of which such director or officer excused for the negligence, default, breach of duty or breach of trust, that may be guilty in relation to the company. court may relieve him, either wholly or partly, from any liability on such terms as the court may think fit. This provision has been interpreted to apply only to Our bye-laws provide that we shall indemnify our officers and directors in actions brought by or on behalf of the company against the directors. respect of their actions and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which By comparison, under Delaware law, the business and affairs of a corporation such director is not legally entitled, and (by incorporation of the provisions are managed by or under the direction of its board of directors. In exercising of the Bermuda Companies Act) that we may advance monies to our officers their powers, directors are charged with a duty of care and a duty of loyalty. and directors for costs, charges and expenses incurred by our officers and directors in defending any civil or criminal proceeding against them on the The duty of care requires that directors act in an informed and deliberate condition that the officers and directors repay the monies if any allegation manner and to inform themselves, prior to making a business decision, of of fraud or dishonesty is proved against them provided, however, that, if all relevant material information reasonably available to them. The duty of the Bermuda Companies Act requires, an advancement of expenses shall be care also requires that directors exercise care in overseeing the conduct of made only upon delivery to the Company of an undertaking, by or on behalf corporate employees. The duty of loyalty is the duty to act in good faith, not of such indemnitee, to repay all amounts so advanced if it shall ultimately out of self-interest, and in a manner which the director reasonably believes be determined by final judicial decision from which there is no further to be in the best interests of the shareholders. A party challenging the right to appeal that such indemnitee is not entitled to be indemnified for propriety of a decision of a board of directors bears the burden of rebutting such expenses under this Bye-law or otherwise. Our bye-laws provide that the presumptions afforded to directors by the “business judgment rule.” If the company and the shareholders waive all claims or rights of action that the presumption is not rebutted, the business judgment rule attaches to they might have, individually or in right of the company, against any of the protect the directors and their decisions. Where, however, the presumption is company’s directors or officers for any act or failure to act in the performance rebutted, the directors bear the burden of demonstrating the fairness of the of such director’s or officers’ duties, except with respect to any fraud or relevant transaction. Notwithstanding the foregoing, Delaware courts subject dishonesty, or to recover any gain, personal profit or advantage to which such directors’ conduct to enhanced scrutiny in respect of defensive actions taken director is not legally entitled. in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation. Meetings of shareholders Interested directors Under Bermuda law, a company is required to convene the annual general meeting of shareholders each calendar year, unless the shareholders in Pursuant to our bye-laws, a director shall declare the nature of his interest in a general meeting, elect to dispense with the holding of annual general any contract or arrangement with the company as required by the Bermuda meetings. Under Bermuda law and our bye-laws, a special general meeting of Companies Act. A director so interested shall not, except in particular shareholders may be called by the board of directors and may be called upon circumstances set out in our bye-laws, be entitled to vote or be counted in the the requisition of shareholders holding not less than 10% of the paid-up capital quorum at a meeting in relation to any resolution in which he has an interest, of the company carrying the right to vote at general meetings of shareholders. which is to his knowledge, a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of or otherwise in or Our bye-laws provide that, at any general meeting of the shareholders, the through the company). A director will be liable to us for any secret profit presence in person or by proxy of two or more shareholders representing in realized from the transaction. In contrast, under Delaware law, such a contract excess of 50% of the total issued voting shares of the company shall constitute or arrangement is voidable unless it is approved by a majority of disinterested a quorum for the transaction of business unless the company only has one directors or by a vote of shareholders, in each case if the material facts as to shareholder, in which case such shareholder shall constitute a quorum. Unless the interested director’s relationship or interests are disclosed or are known to otherwise required by law or by our bye-laws, shareholder action requires a the disinterested directors or shareholders, or such contract or arrangement resolution adopted by a majority of votes cast by shareholders at a general is fair to the corporation as of the time it is approved or ratified. Additionally, meeting at which a quorum is present. such interested director could be held liable for a transaction in which such director derived an improper personal benefit. GeoPark 139 Shareholder proposals of the shareholders meeting, apply to the Supreme Court of Bermuda to Under Bermuda law, shareholders holding at least 5% of the total voting rights appraise the value of those shares. of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group composed of at Under the Bermuda Companies Act, we are not required to seek the least 100 or more shareholders may require a proposal to be submitted to an approval of our shareholders for the sale of all or substantially all of our annual general meeting of shareholders. Under our bye-laws, any shareholders assets. However, Bermuda courts will view decisions of the English courts wishing to nominate a person for election as a director or propose business to as highly persuasive and English authorities suggest that such sales do be transacted at a meeting of shareholders must provide (among other things) require shareholder approval. Our bye-laws provide that the directors shall advance notice, as set out in our bye-laws. Shareholders may only propose a manage the business of the Company and may exercise all such powers as person for election as a director at an annual general meeting. are not, by the Bermuda Companies Act or by these Bye-laws, required to Shareholder action by written consent be exercised by the Company in general meeting and may pay all expenses incurred in promoting and incorporating the company and may exercise Our bye-laws provide that, except for the removal of auditors and all the powers of the Company including, but not by way of limitation, the directors, any actions which shareholders may take at a general meeting power to borrow money and to mortgage or charge all or any part of the of shareholders may be taken by the shareholders through the unanimous undertaking property and assets (present and future) and uncalled capital written consent of the shareholders who would be entitled to vote on the of the Company and to issue debentures and other securities, whether matter at the general meeting. outright or as collateral security for any debt, liability or obligation of the Company or any other persons. Amendment of memorandum of association and bye-laws Our memorandum of association and bye-laws may be amended with the Under Bermuda law, where an offer is made for shares of a company and, approval of a majority of our board of directors and by a resolution by a within four months of the offer, the holders of not less than 90% of the majority of the votes cast by shareholders who (being entitled to do so) vote in shares not owned by the offeror, its subsidiaries or their nominees accept person or by proxy at any general meeting of the shareholders in accordance such offer, the offeror may by notice require the non-tendering shareholders with the provisions of the bye-laws. Business combinations to transfer their shares on the terms of the offer. Dissenting shareholders do not have express appraisal rights but are entitled to seek relief (within one month of the compulsory acquisition notice) from the court, which has A Bermuda company may engage in a business combination pursuant to a power to make such orders as it thinks fit. Additionally, where one or more tender offer, amalgamation, merger or sale of assets. The amalgamation or parties hold not less than 95% of the shares of a company, such parties merger of a Bermuda company with another company generally requires may, pursuant to a notice given to the remaining shareholders, acquire the the amalgamation or merger agreement to be approved by the company’s shares of such remaining shareholders. Dissenting shareholders have a right board of directors and by its shareholders. Shareholder approval is not to apply to the court for appraisal of the value of their shares within one required where (a) a holding company and one or more of its wholly-owned month of the compulsory acquisition notice. If a dissenting shareholder is subsidiary companies amalgamate or merge or (b) two or more wholly- successful in obtaining a higher valuation, that valuation must be paid to all owned subsidiary companies of the same holding company amalgamate shareholders being squeezed out or the purchaser may cancel the purchase or merge. Under the Bermuda Companies Act (save for such “short-form notice sent. amalgamations”), unless a company’s bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to pass Dividends and repurchase of shares a resolution to approve the amalgamation or merger agreement, and the Pursuant to our bye-laws, our board of directors has the authority to declare quorum for such meeting must be two persons holding or representing dividends and authorize the repurchase of shares subject to applicable law. more than one-third of the issued shares of the company. Our bye-laws Under Bermuda law, a company may not declare or pay a dividend if there provide that an amalgamation or merger will require the approval of our are reasonable grounds for believing that the company is, or would after the board of directors and of our shareholders by a resolution adopted by 65% payment be, unable to pay its liabilities as they become due or the realizable or more of the votes cast by shareholders who (being entitled to do so) value of its assets would thereby be less than its liabilities. Under Bermuda law, vote in person or by proxy at any general meeting of the shareholders in a company cannot purchase its own shares if there are reasonable grounds for accordance with the provisions of the bye-laws. Under Bermuda law, in the believing that the company is, or after the repurchase would be, unable to pay event of an amalgamation or merger of a Bermuda company with another its liabilities as they become due. company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been Shareholder suits offered for such shareholder’s shares may, within one month of the notice Class actions and derivative actions are generally not available to 140 GeoPark 20F shareholders under Bermuda law. The Bermuda courts, however, would arrangement with the company. Our bye-laws further provide that a director ordinarily be expected to permit a shareholder to commence an action so interested shall not, except in particular circumstances, be entitled to in the name of a company to remedy a wrong to the company where vote or be counted in the quorum at a meeting in relation to any resolution the act complained of is alleged to be beyond the corporate power of in which he has an interest, which is to his knowledge, a material interest the company or illegal, or would result in the violation of the company’s (otherwise than by virtue of his interest in shares or debentures or other memorandum of association or bye-laws. Furthermore, consideration securities of or otherwise in or through the company). A director will be would be given by a Bermuda court to acts that are alleged to constitute liable to us for any secret profit realized from the transaction. See “Item a fraud against the minority shareholders or where an act requires the 10—B. Memorandum of association and bye-laws—Interested Directors.” approval of a greater percentage of the company’s shareholders than that which actually approved it. Amalgamations, Mergers and Similar Arrangements. Pursuant to the Bermuda Companies Act, the amalgamation or merger of a Bermuda company with When the affairs of a company are being conducted in a manner which is another company or corporation requires the amalgamation or merger oppressive or prejudicial to the interests of some part of the shareholders, agreement to be approved by the company’s board of directors and, one or more shareholders may apply under the Bermuda Companies under certain circumstances, by its shareholders. Under our bye-laws, an Act for an order of the Supreme Court of Bermuda, which may make amalgamation or merger will require the approval of our board of directors such order as it sees fit, including an order regulating the conduct of the and our shareholders by Special Resolution, which is a resolution adopted company’s affairs in the future or ordering the purchase of the shares of by 65% of more of the votes cast by shareholders who (being entitled to do any shareholders by other shareholders or by the company. so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws and the quorum for Our bye-laws contain a provision through which we and our shareholders any general meeting must be two or more persons, in person or by proxy, waive any claim or right of action that we or they have, both individually representing in excess of 50% of the total of our issued voting shares. Under and on our behalf, against any director or officer in relation to any action or Bermuda law, in the event of an amalgamation or merger of a Bermuda failure to take action by such director or officer, including the breach of any company with another company or corporation, a shareholder of the fiduciary duty, except in respect of any fraud or dishonesty of such director Bermuda company who did not vote in favor of the amalgamation or merger or officer. and who is not satisfied that he has been offered fair value for his shares may, within one month of notice of the shareholders meeting, apply to the Comparison of Bermuda law to Delaware corporate law Supreme Court of Bermuda to appraise the fair value of those shares. Bermuda law differs from the laws in effect in the United States and might Under Delaware law, with certain exceptions, a merger, consolidation or afford less protection to shareholders. sale of all or substantially all the assets of a corporation must be approved Our shareholders could have more difficulty protecting their interests by the board of directors and a majority of the issued and outstanding than would shareholders of a corporation incorporated in a jurisdiction shares entitled to vote thereon. Under Delaware law, a shareholder of a of the United States. As a Bermuda company, we are governed by our corporation participating in certain major corporate transactions may, under memorandum of association and bye-laws and Bermuda company certain circumstances, be entitled to appraisal rights pursuant to which law. The provisions of the Bermuda Companies Act, which applies to such shareholder may receive cash in the amount of the fair value of the us, differs in some material respects from laws generally applicable to shares held by such shareholder (as determined by a court) in lieu of the U.S. corporations and shareholders, including the provisions relating to consideration such shareholder would otherwise receive in the transaction. interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of Shareholders’ Suit. Class actions and derivative actions are generally not these provisions, as well as modifications adopted pursuant to our bye-laws, available to shareholders under Bermuda law. The Bermuda courts, however, which differ in certain respects from provisions of Delaware corporate law. would ordinarily be expected to permit a shareholder to commence an Our shareholders approved the adoption of new bye-laws which came into action in the name of a company to remedy a wrong to the company effect on February 19, 2014, being the date on which the company cancelled where the act complained of is alleged to be beyond the corporate power admission of its common shares on AIM. Because the following statements of the company or illegal, or would result in the violation of the company’s are summaries, they do not discuss all aspects of Bermuda law that may be memorandum of association or bye-laws. When the affairs of a company relevant to us and our shareholders. are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders Interested Directors. Under our bye-laws and the Bermuda Companies may apply for an order of the Supreme Court of Bermuda regulating the Act, a director shall declare the nature of his interest in any contract or conduct of the company’s affairs in the future or an order to purchase the GeoPark 141 shares of any shareholders by other shareholders or by the company and, incorporated in the United States. in the case of a purchase by the company, for the reduction accordingly of the company’s capital, or otherwise. See “Item 10—B. Memorandum of Tax matters. Under current Bermuda law, we are not subject to tax on income association and bye-laws—Shareholder Suits.” or capital gains. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance Our bye-laws contain a provision by virtue of which we and our shareholders that, in the event that Bermuda enacts legislation imposing tax computed waive any claim or right of action that they have, both individually and on on profits, income, any capital asset, gain or appreciation, or any tax in the our behalf, against any director or officer in relation to any action or failure to nature of estate duty or inheritance, then the imposition of any such tax shall take action by such director or officer, including the breach of any fiduciary not be applicable to us or to any of our operations or shares, debentures duty, except in respect of any fraud or dishonesty of such director or officer. or other obligations, until March 31, 2035. We could be subject to taxes in Class actions and derivative actions generally are available to shareholders Bermuda after that date. This assurance is subject to the provision that it is under Delaware law for, among other things, breach of fiduciary duty, not to be construed to prevent the application of any tax or duty to such corporate waste and actions not taken in accordance with applicable law. In persons as are ordinarily resident in Bermuda or to prevent the application such actions, the court has discretion to permit the winning party to recover of any tax payable in accordance with the provisions of the Land Tax Act attorneys’ fees incurred in connection with such action. 1967 or otherwise payable in relation to any property leased to us. We are incorporated in Bermuda as an exempted company and pay annual Bermuda Indemnification of Directors. We may indemnify our directors and officers in government fees. In addition, all entities employing individuals in Bermuda their capacity as directors or officers for any loss arising or liability attaching are required to pay a payroll tax and there are other sundry taxes payable, to them by virtue of any rule of law in respect of any negligence, default, directly or indirectly, to the Bermuda government. Neither we nor our breach of duty or breach of trust of which a director or officer may be Bermuda subsidiaries employ individuals in Bermuda as at the date of this guilty in relation to the company other than in respect of his own fraud or annual report. dishonesty. See “Item 10—B. Memorandum of association and bye-laws— Enforcement of Judgments.” Our bye-laws provide that we shall indemnify Access to books and records and dissemination of information our officers and directors in respect of their acts and omissions, except Members of the general public have a right to inspect the public documents in respect of their fraud or dishonesty, or to recover any gain, personal of a company available at the office of the Registrar of Companies in profit or advantage to which such Director is not legally entitled, and (by Bermuda. These documents include the company’s memorandum of incorporation of the provisions of the Bermuda Companies Act) that we association and any amendments thereto. The shareholders have the may advance money to our officers and directors for the costs, charges additional right to inspect the bye-laws of the company, minutes of general and expenses incurred by our officers and directors in defending any civil meetings of shareholders and the company’s audited financial statements. or criminal proceedings against them on condition that the directors and The company’s audited financial statements must be presented at the officers repay the money if any allegations of fraud or dishonesty is proved annual general meeting of shareholders, unless the board and all the against them provided, however, that, if the Bermuda Companies Act shareholders agree to the waiving of the audited financials. The company’s requires, an advancement of expenses shall be made only upon delivery share register is open to inspection by shareholders and by members of to the Company of an undertaking, by or on behalf of such indemnitee, to the general public without charge. A company is required to maintain its repay all amounts if it shall ultimately be determined by final decision that share register in Bermuda but may, subject to the provisions of the Bermuda such indemnitee is not entitled to be indemnified for such expenses under Companies Act, establish a branch register outside of Bermuda. Bermuda our Bye-laws or otherwise. Under Delaware law, a corporation may indemnify law does not, however, provide a general right for shareholders to inspect or a director or officer of the corporation against expenses (including attorneys’ obtain copies of any other corporate records. fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of Registrar or transfer agent such position if such director or officer acted in good faith and in a manner A register of holders of the common shares is maintained by Coson Corporate he or she reasonably believed to be in or not opposed to the best interests Services Limited in Bermuda, and a branch register is maintained in the of the corporation and, with respect to any criminal action or proceeding, United States by Computershare Trust Company, N.A., who serves as branch such director or officer had no reasonable cause to believe his or her conduct registrar and transfer agent. was unlawful. In addition, we have entered into customary indemnification agreements with our directors. Enforcement of Judgments As a result of these differences, investors could have more difficulty under the laws of Bermuda, and substantially all of our assets are located protecting their interests than would shareholders of a corporation in Colombia, Chile, Brazil, Argentina and Peru. In addition, most of our We are incorporated as an exempted company with limited liability 142 GeoPark 20F directors and executive officers reside outside the United States, and all or Our bye-laws contain provisions whereby we and our shareholders waive a substantial portion of the assets of such persons are located outside the any claim or right of action that we have, both individually and on our behalf, United States. As a result, it may be difficult for investors to effect service of against any director or officer in relation to any action or failure to take action process on those persons in the United States or to enforce in the United by such director or officer, except in respect of any fraud or dishonesty of States judgments obtained in U.S. courts against us or those persons based such director or officer. We may also indemnify our directors and officers on the civil liability provisions of the U.S. securities laws. in their capacity as directors and officers for any loss arising or liability There is no treaty in force between the United States and Bermuda providing default, breach of trust of which a director or officer may be guilty in relation for the reciprocal recognition and enforcement of judgments in civil to the company other than in respect of his own fraud or dishonesty. We and commercial matters. As a result, whether a U.S. judgment would be have entered into customary indemnification agreements with our directors. attaching to them by virtue of any rule of law in respect of any negligence, 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 No treaty exists between the United States and Chile for the reciprocal Bermuda court as having jurisdiction over us or our directors and officers, as recognition and enforcement of foreign judgments. Chilean courts, however, determined by reference to Bermuda conflict of law rules and the judgment have enforced valid and conclusive judgments for the payment of money is not contrary to public policy in Bermuda, has not been obtained by fraud rendered by competent U.S. courts by virtue of the legal principles of in proceedings contrary to natural justice and is not based on an error reciprocity and comity, subject to review in Chile of the U.S. judgment in in Bermuda law. A judgment debt from a U.S. court that is final and for a order to ascertain whether certain basic principles of due process and public sum certain based on U.S. federal securities laws will not be enforceable in policy have been respected, without retrial or review of the merits of the Bermuda unless the judgment debtor had submitted to the jurisdiction of subject matter. If a U.S. court grants a final judgment, enforceability of this the U.S. court, and the issue of submission and jurisdiction is a matter of judgment in Chile will be subject to obtaining the relevant exequatur (i.e., Bermuda (not U.S.) law. recognition and enforcement of the foreign judgment) according to Chilean civil procedure law in effect at that time, and depending on certain factors An action brought pursuant to a public or penal law, the purpose of which is (the satisfaction or non-satisfaction of which would be determined by the the enforcement of a sanction, power or right at the instance of the state in Supreme Court of Chile). Currently, the most important of such factors are: its sovereign capacity, may not be entertained by a Bermuda court. Certain the existence of reciprocity (if it can be proved that there is no reciprocity remedies available under the laws of U.S. jurisdictions, including certain in the recognition and enforcement of the foreign judgment between the remedies under U.S. federal securities laws, may not be available under United States and Chile, that judgment would not be enforced in Chile); the Bermuda law or enforceable in a Bermuda court, as they may be contrary absence of any conflict between the foreign judgment and Chilean laws to Bermuda public policy. Further, no claim may be brought in Bermuda (excluding for this purpose the laws of civil procedure) and Chilean public against us or our directors and officers in the first instance for violations policy; the absence of a conflicting judgment by a Chilean court relating of U.S. federal securities laws because these laws have no extraterritorial to the same parties and arising from the same facts and circumstances; jurisdiction under Bermuda law and do not have force of law in Bermuda. A the Chilean court’s determination that the U.S. courts had jurisdiction, that Bermuda court may, however, impose civil liability on us or our directors and process was appropriately served on the defendant and that the defendant officers if the facts alleged in a complaint constitute or give rise to a cause of was afforded a real opportunity to appear before the court and defend its action under Bermuda law. However, section 281 of the Bermuda Companies case; and the judgment being final under the laws of the country in which Act allows a Bermuda court, in certain circumstances, to relieve officers and it was rendered. Nonetheless, we have been advised by our Chilean counsel directors of Bermuda companies of liability for acts of negligence, breach of that there is doubt as to the enforceability in original actions in Chilean duty or trust or other defaults. courts of liabilities predicated solely upon U.S. federal or state securities laws. Section 98 of the Bermuda Companies Act provides generally that a Bermuda C. Material contracts company may indemnify its directors, officers and auditors against any See “Item 4. Information on the Company—B. Business Overview—Significant liability which by virtue of any rule of law would otherwise be imposed on Agreements.” them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which D. Exchange controls such director, officer or auditor may be guilty in relation to the company. Not applicable. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in E. Taxation defending any proceedings, whether civil or criminal, in which judgment The following summary contains a description of certain Bermudian, U.S. is awarded in their favor or in which they are acquitted or granted relief by federal income, and Chilean tax consequences of the acquisition, ownership and the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda Companies Act. GeoPark 143 disposition of our common shares. The summary is based upon the tax laws of purposes holds common shares, the U.S. federal income tax treatment of a Bermuda, the United States, and Chile, and regulations thereunder as of the date partner will generally depend on the status of the partner and the activities hereof, which are subject to change. Bermuda tax consideration of the partnership. Partnerships holding common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of their investment in our common shares. At the date of this annual report, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance This discussion is based on the Internal Revenue Code of 1986, as amended tax payable by us or by our shareholders in respect of our common shares. We (the “Code”), administrative pronouncements, judicial decisions, and final, have obtained an assurance from the Minister of Finance of Bermuda under temporary and proposed Treasury regulations, all as of the date hereof, any the Exempted Undertakings Tax Protection Act 1966 that, in the event that of which is subject to change, possibly with retroactive effect. U.S. Holders any legislation is enacted in Bermuda imposing any tax computed on profits should consult their tax advisers concerning the U.S. federal, state, local and or income, or computed on any capital asset, gain or appreciation or any tax in foreign tax consequences of owning and disposing of our common shares in the nature of estate duty or inheritance tax, such tax shall not, until March 31, their particular circumstances. 2035, be applicable to us or to any of our operations or to our common shares, debentures or other obligations except insofar as such tax applies to persons A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal ordinarily resident in Bermuda or is payable by us in respect of real property income tax purposes that is: owned or leased by us in Bermuda. We pay annual Bermuda government fees. • a citizen or individual resident of the United States; Material U.S. federal income tax considerations in or under the laws of the United States, any state therein or the District of The following is a description of the material U.S. federal income tax Columbia; or consequences to U.S. Holders (as defined below) of owning and disposing of • an estate or trust the income of which is subject to U.S. federal income • a corporation, or other entity taxable as a corporation, created or organized our common shares. This discussion is not a comprehensive description of taxation regardless of its source. all tax considerations that may be relevant to a particular person’s decision to hold our common shares. This discussion applies only to a U.S. Holder that This discussion assumes that we are not, and will not become, a passive holds our common shares as capital assets for tax purposes. In addition, it foreign investment company, as described below. does not describe all of the tax consequences that may be relevant in light of the U.S. Holder’s particular circumstances, including alternative minimum tax Taxation of distributions and Medicare contribution tax consequences and differing tax consequences Distributions paid on our common shares, other than certain pro rata applicable to a U.S. Holder subject to special rules, such as: distributions of common shares, will generally be treated as dividends to • certain financial institutions; the extent paid out of our current or accumulated earnings and profits (as • a dealer or trader in securities who uses a mark-to-market method of tax determined under U.S. federal income tax principles). Because we do not accounting; maintain calculations of our earnings and profits under U.S. federal income tax • a person holding common shares as part of a straddle, wash sale or principles, it is expected that distributions will generally be reported to U.S. conversion transaction or entering into a constructive sale with respect to the Holders as dividends. Subject to the passive foreign investment company rules common shares; described below, dividends paid by qualified foreign corporations to certain non- • a person whose functional currency for U.S. federal income tax purposes is corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is not the US$; treated as a qualified foreign corporation with respect to dividends paid on stock • a partnership or other entities classified as partnerships for U.S. federal that is readily tradable on a securities market in the United States, such as the income tax purposes; NYSE where our common shares are traded. Non-corporate U.S. Holders should • a tax-exempt entity, including an “individual retirement account” or “Roth consult their tax advisers to determine whether the favorable rate will apply to IRA;” dividends they receive and whether they are subject to any special rules that • a person that owns or is deemed to own 10% or more of our shares by vote limit their ability to be taxed at this favorable rate. or value; A dividend generally will be included in a U.S. Holder’s income when received, • a person who acquired our shares pursuant to the exercise of an employee will be treated as foreign-source income to U.S. Holders and will not be eligible stock option or otherwise as compensation; or for the dividends-received deduction generally available to U.S. corporations • a person holding common shares in connection with a trade or business under the Code with respect to dividends paid by domestic corporations. conducted outside of the United States. If an entity that is classified as a partnership for U.S. federal income tax Sale or other taxable disposition of common shares 144 GeoPark 20F Gain or loss realized on the sale or other taxable disposition of our common treated as a PFIC for the taxable year in which we paid a dividend or the prior shares will be capital gain or loss, and will be long-term capital gain or loss if taxable year, the preferential dividend rates discussed above with respect to the U.S. Holder held our common shares for more than one year. Long-term dividends paid to certain non-corporate U.S. Holders would not apply. capital gain of a non-corporate U.S. Holder is generally taxed at preferential rates. The deductibility of capital losses is subject to limitations. The amount Information reporting and backup withholding of the gain or loss will equal the difference between the U.S. Holder’s tax Payments of dividends and sales proceeds that are made within the United basis in the common shares disposed of and the amount realized on the States or through certain U.S.-related financial intermediaries generally are disposition. If a Chilean tax is withheld on the sale or disposition of common subject to information reporting, and may be subject to backup withholding, shares, a U.S. Holder’s amount realized will include the gross amount of the unless (1) the U.S. Holder is a corporation or other exempt recipient or proceeds of the sale or disposition before deduction of the Chilean tax. See (2) in the case of backup withholding, the U.S. Holder provides a correct “—Chilean tax on transfers of shares” for a description of when a disposition taxpayer identification number and certifies that it is not subject to backup may be subject to taxation by Chile. This gain or loss will generally be withholding. The amount of any backup withholding from a payment to a U.S.-source gain or loss for foreign tax credit purposes. U.S. Holders should U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal consult their tax advisers as to whether the Chilean tax on gains may be income tax liability and may entitle it to a refund, provided that the required creditable against the U.S. Holder’s U.S. federal income tax on foreign-source information is timely furnished to the Internal Revenue Service. income from other sources. Chilean tax on transfers of shares Passive foreign investment company rules In September 2012, Article 10 of the Chilean Income Tax Law Decree Law No. We believe that we were not a “passive foreign investment company,” or PFIC, 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes for U.S. federal income tax purposes for 2018, and we do not expect to be on the indirect transfer of shares, equity rights, interests or other rights in a PFIC in the foreseeable future. However, because the composition of our the equity, control or profits of a Chilean entity as well as transfers of other income and assets will vary over time, there can be no assurance that we will assets and property of permanent establishments or other businesses in Chile. not be a PFIC for any taxable year. The determination of whether we are a PFIC Reforms introduced in 2014 imposed a measure which obliges the company is made annually and is based upon the composition of our income and assets from which shares are transferred to pay taxes if the entity which undertakes (including the income and assets of, among others, entities in which we hold the transfer of shares fails to do so. at least a 25% interest), and the nature of our activities. The indirect transfer rules apply to sales of shares of an entity: If we were a PFIC for any taxable year during which a U.S. Holder held our • If such entity is an offshore holding company located in a black-listed common shares, gain recognized by a U.S. Holder on a sale or other disposition tax haven jurisdiction as determined by Chilean tax law, or a black-listed (including certain pledges) of our common shares would generally be jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean allocated ratably over the U.S. Holder’s holding period for the common shares. resident holds 5% or more of such entity, or such entity’s rights to equity, The amounts allocated to the taxable year of the sale or other disposition control or profits, or 50% or more of such entity’s rights to equity or profits are and to any year before we became a PFIC would be taxed as ordinary income. held by residents in black-listed jurisdictions; or The amount allocated to each other taxable year would be subject to tax • the shares or rights transferred represent 10% or more of the offshore at the highest rate in effect for individuals or corporations for that year, as holding company (considering dispositions by related persons and over the appropriate, and an interest charge would be imposed on the tax on such preceding 12-month period) and the underlying Chilean Assets indirectly amount. Further, to the extent that any distribution received by a U.S. Holder transferred, in the proportion indirectly owned by the seller, (a) are valued on its common shares exceeds 125% of the average of the annual distributions in an amount equal to or higher than UTA 210,000 (approximately US$200 on the shares received during the preceding three years or the U.S. Holder’s million) (adjusted by the Chilean inflation unit of reference) or (b) represent holding period, whichever is shorter, that distribution would be subject to 20% or more of the market value of the interest held by such seller in such taxation in the same manner as gain, as described immediately above. Certain offshore holding company. elections may be available that would result in alternative treatments (such As a result of these rules, a capital gain tax of 35% will be applied by the as mark-to-market treatment) of our common shares. U.S. Holders should Chilean tax authorities to the sale of any of our common shares if either of the consult their tax advisers to determine whether any of these elections would above tests are met. This rate might be subject to change in the short term. be available and, if so, what the consequences of the alternative treatments See “Item 4. Information on the Company—B. Business overview—Industry would be in their particular circumstances. and regulatory framework —Chile.” As of December 31, 2018, our Chilean Assets represented more than UTA Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were 210,000 and represent more than 32% of our total assets. GeoPark 145 PART II The 35% rate is calculated pursuant to one of the following methods, as F. Dividends and paying agents determined by the seller: Not applicable. • the sale price of the shares minus the acquisition cost of such shares, multiplied by the percentage or proportion of the part of the underlying Chilean G. Statement by experts Assets’ fair market value (which assets are deemed to be “indirectly transferred” Not applicable. by virtue of the sale of shares) to the fair market value of the shares of the seller; or H. Documents on display • the portion of the sales price of the shares equal to the proportion of the We are subject to the informational requirements of the Exchange Act. fair market value of the underlying Chilean Assets, minus the corresponding Accordingly, we are required to file reports and other information with the proportion in the tax cost of such Chilean Assets for the corresponding holding SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC entity. maintains an Internet website that contains reports and other information about issuers, like us, that file electronically with the SEC. The address of that However, the seller may opt to be taxed as if the underlying Chilean Assets website is www.sec.gov. had been sold directly in which case a different set of tax rules may apply. I. Subsidiary information The tax is payable by the seller of the shares; however, the buyer shall make a Not applicable. provisional withholding unless the seller declares and pays the tax within the month following the sale, payment, remittance or it is credited into its account ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT or is put at its disposal. Also, if the seller fails to declare and pay this tax, and MARKET RISK the buyer has not complied with its withholding obligations, the Chilean tax authority (Servicio de Impuestos Internos) may charge such tax directly to any We are exposed to a variety of market risks, including commodity price risk, of them. In addition, the Chilean tax authority may require us, the seller, the interest rate risk, currency risk and credit (counterparty and customer) risk. buyer, or its representative in Chile, to file an affidavit with the information The term “market risk” refers to the risk of loss arising from adverse changes in necessary to assess this tax. interest rates, oil and natural gas prices and foreign currency exchange rates. Based on information available to us, (i) no Chilean resident holds 5% or For further information on our market risks, please see Note 3 to our more of our rights to equity, control or profits; and (ii) residents in black-listed Consolidated Financial Statements. jurisdictions do not hold 50% or more of our rights to equity, control or profits. Therefore, we do not believe the indirect transfer rules will apply to transfers ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES of our common shares, unless the shares or rights transferred represent 10% or more of the company and the other conditions described above are met A. Debt securities (considering dispositions by related persons and over the preceding 12-month Not applicable. period). However, there can be no assurance that, at any time in the future, a Chilean Not applicable. resident will not hold 5% or more of our rights to equity, control or profits or that residents in black-listed jurisdictions will not hold 50% or more of our C. Other securities rights to equity, control or profits. If this were to occur, all sales of our common Not applicable. shares would be subject to the indirect transfer tax referred to above. D. American Depositary Shares B. Warrants and rights Our expectations regarding the indirect transfer rules are based on our Not applicable. understandings, analysis and interpretation of these enacted indirect transfer ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES rules, which are subject to additional interpretation and rule-making by the Chilean authorities. As such, there is uncertainty relating to the application by A. Defaults Chilean authorities of the indirect transfer rules on us. No matters to report. See “Item 3. Key Information—D. Risk Factors—Risks related to our common B. Arrears and delinquencies shares—The transfer of our common shares may be subject to capital gains No matters to report. taxes pursuant to indirect transfer rules in Chile.” 146 GeoPark 20F ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY Because of its inherent limitations, internal control over financial reporting HOLDERS AND USE OF PROCEEDS Not applicable. ITEM 15. CONTROLS AND PROCEDURES A. Disclosure Controls and Procedures may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projections of, and any evaluation of effectiveness of the internal controls in future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. As of December 31, 2018, under the supervision and with the participation Under the supervision and with the participation of our management, of our management, including our Chief Executive Officer and Chief Financial including our Chief Executive Officer, our Chief Financial Officer, and our Officer, we performed an evaluation of the effectiveness of the design and Director of Legal and Governance, we conducted an evaluation of the operation of our disclosure controls and procedures (as defined in Rule effectiveness of our internal control over financial reporting as of December 13a-15(e) under the Exchange Act). There are inherent limitations to the 31, 2018, based on the criteria established in Internal Control - Integrated effectiveness of any disclosure controls and procedures system, including Framework of the Committee of Sponsoring Organizations of the Treadway the possibility of human error and circumventing or overriding them. Even Commission (2013). if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on this assessment, management believes that, as of December 31, 2018, its internal control over financial reporting was effective based on those Based on such evaluation, our Chief Executive Officer and Chief Financial criteria. Officer concluded that our disclosure controls and procedures are effective to provide reasonable assurance that the information we are required to disclose C. Attestation Report of the Registered Public Accounting Firm in the reports we file or submit under the Exchange Act is (1) recorded, The effectiveness of the Company´s internal control over financial reporting as processed, summarized and reported within the time periods specified in of December 31, 2018, has been audited by Price Waterhouse & Co. S.R.L., an the SEC’s rules and forms and (2) accumulated and communicated to our independent registered public accounting firm, as stated in their report which management to allow timely decisions regarding required disclosures. is included on page F-2 of our Consolidated Financial Statements herein. B. Management’s Annual Report on Internal Control over Financial D. Changes in Internal Control over Financial Reporting Reporting There have been no changes in our internal control over financial reporting Our management is responsible for establishing and maintaining an during the period covered by this annual report on Form 20-F that have adequate internal control over financial reporting as defined in Rule materially affected or reasonably likely to materially affect our internal control 13a-15(f ) under the Exchange Act. over financial reporting. Our internal control over financial reporting is a process designed by, or ITEM 16. RESERVED under the supervision of, our principal executive and principal financial officers, management and other personnel, to provide reasonable assurance ITEM 16A. Audit committee financial expert regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes, in accordance with We have determined that Mr. Juan Cristóbal Pavez, Mr. Constantine generally accepted accounting principles. These include those policies and Papadimitriou and Mr. Robert Bedingfield are independent, as such term is procedures that: defined under SEC rules applicable to foreign private issuers. In addition, Mr. • pertain to the maintenance of records that, in reasonable detail, accurately Robert Bedingfield is regarded as audit committee financial expert. and fairly reflect transactions and dispositions of our assets; • provide reasonable assurance that transactions are recorded as necessary ITEM 16B. Code of Conduct to permit preparation of financial statements, in accordance with generally accepted accounting principles, and that receipts and expenditures are being We have adopted a code of conduct applicable to the board of directors and made only in accordance with authorization of our management and directors; all employees. Since its effective date on September 24, 2012, we have not and waived compliance with or amended the code of conduct. • provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a ITEM 16C. Principal Accountant Fees and Services material effect on our financial statements. GeoPark 147  Amounts billed by PwC for audit and other services were as follows: ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers. 2018 2017 The following table presents purchases of our common shares by the company (in millions of US$) and “affiliated purchasers” (as that term is defined in Rule 10b-18(a)(3) under the Audit fees Audit related fees Tax services fees Other fees paid Total Audit Fees 0.80 - 0.21 - 1.01 0.73 0.14 0.21 0.03 1.11 Securities Exchange Act of 1934, as amended) during 2018: Total Number Maximum Number of Shares (or Approximate Purchased as Dollar Value) of Total Part of Publicly Shares that May Audit fees are fees billed for professional services rendered by the principal Number Average Announced Yet be Purchased accountant for the audit of the registrant’s annual financial statements or of Shares Price Paid Plans or Under the Plans or services that are normally provided by the accountant in connection with 2018 Purchased per Share Programs Programs statutory and regulatory filings or engagements for those fiscal years. It includes December 21 the audit of our Consolidated Financial Statements and other services that to December generally only the independent accountant reasonably can provide, such as 31, 2018 145,917 12.0 145,917 6,063,000 shares comfort letters, statutory audits, consents and assistance with and review of documents filed with the SEC. ITEM 16F. Change in registrant’s certifying accountant Audit-Related Fees Not applicable. Audit-related fees are fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our Consolidated ITEM 16G. Corporate governance Financial Statements and not reported under the previous category. These services would include, among others: accounting consultations and audits Our common shares are listed on the NYSE. We are therefore required to in connection with acquisitions, internal control reviews, attest services that comply with certain of the NYSE’s corporate governance listing standards are not required by statue or regulation and consultation concerning financial (the “NYSE Standards”). As a foreign private issuer, we may follow our accounting and reporting standards. Tax Fees home country’s corporate governance practices in lieu of most of the NYSE Standards. Our corporate governance practices differ in certain significant respects from those that U.S. companies must adopt in order to maintain Tax fees are fees billed for professional services for tax compliance, tax advice NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed and tax planning. Company Manual, a brief, general summary of those differences is provided Pre-Approval Policies and Procedures Following the listing of our common shares on the NYSE, the Audit Director independence as follows. Committee proposes the appointment of the independent auditor to the The NYSE Standards require a majority of the membership of NYSE-listed Board to be put to shareholders for approval at the Annual General meeting. company boards to be composed of independent directors. Neither The committee oversees the auditor selection process for new auditors Bermuda law, the law of our country of incorporation, nor our memorandum and ensures key partners in the appointed firm are rotated in accordance of association or bye-laws require a majority of our board to consist of with best practices. Also, following our NYSE listing, the Audit Committee independent directors. is required to pre-approve the audit and non-audit fees and services Non-management directors’ executive sessions performed by the Company’s auditors in order to be sure that the provision The NYSE Standards require non-management directors of NYSE-listed of such services does not impair the audit firm’s independence. companies to meet at regularly scheduled executive sessions without management. Our memorandum of association and bye-laws do not require All of the audit fees, audit-related fees and tax fees described in this item our non-management directors to hold such meetings. 16C have been approved by the Audit Committee. ITEM 16D. Exemptions from the listing standards for audit committees The NYSE Standards require domestic NYSE-listed domestic companies to Committee member composition None. 148 GeoPark 20F have a nominating/corporate governance committee and a compensation committee that are composed entirely of independent directors. Bermuda law, purposes and responsibilities or performance evaluations in a manner that the law of our country of incorporation, does not impose similar requirements. would satisfy the NYSE’s requirements; acquire shareholder approval of equity compensation plans in certain cases; or adopt and make publicly available Independence of the compensation committee and its advisers corporate governance guidelines. On January 11, 2013, the SEC approved NYSE listing standards that require that the board of directors of a domestic listed company consider two factors We are incorporated under, and are governed by, the laws of Bermuda. (in addition to the existing general independence tests) in the evaluation of For a summary of some of the differences between provisions of Bermuda the independence of compensation committee members: (i) the source of law applicable to us and the laws applicable to companies incorporated in compensation of the director, including any consulting, advisory or other Delaware and their shareholders, See “Item 10. Additional Information—B. compensatory fees paid by the listed company, and (ii) whether the director Memorandum of association and bye-laws.” has an affiliate relationship with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. In addition, ITEM 16H. Mine safety disclosure before selecting or receiving advice from a compensation consultant or other adviser, the compensation committee of a listed company will be Not applicable. required to take into consideration six specific factors, as well as all other factors relevant to an adviser’s independence. Foreign private issuers such as us will be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar requirements, so we will not be required to implement the NYSE listing standards relating to compensation committees of domestic listed companies. All of the members of our compensation committee are independent, and the charter of our compensation committee does not require the compensation committee to consider the independence of any advisers that assist them in fulfilling their duties. Additional audit committee functions The NYSE standards require that audit committees of domestic companies to serve a number of functions in addition to reviewing and approving the company’s financial statements, engaging auditors and assessing their independence, and obtaining the legal and other professional advice of experts when necessary. For instance, the NYSE Standards require that the audit committee meet independently with management in a separate session in order to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review a report by the independent auditors describing the firm’s internal quality-control procedures and any issues raised by these procedures. Finally, audit committees are responsible for designing and implementing an internal audit function that assesses the company’s risk management processes and systems of internal control on an ongoing basis. Foreign private issuers such as us are exempt from these additional requirements if home country practice is followed. Bermuda law does not impose similar requirements, and consequently, our audit committee does not perform these additional functions. Our Audit Committee is composed exclusively of independent auditors. Miscellaneous In addition to the above differences, we are not required to: make our audit and compensation committees prepare a written charter that addresses either GeoPark 149 PART III ITEM 17. Financial statements We have responded to Item 18 in lieu of this item. No. Description (incorporated herein by reference to Exhibit 4.22 to the Company’s Annual Report on Form 20-F filed with the SEC on April 11, 2017). † ITEM 18. Financial statements 4.5 Prepayment Agreement for an Amount of up to US$100,000,000, Financial Statements are filed as part of this annual report, see pages F-1 to dated December 18, 2015, among C.I. Trafigura Petroleum Colombia F-79 to this annual report. ITEM 19. Exhibits No. Description SAS, GeoPark Colombia SAS and GeoPark Ltd. (incorporated herein by reference to Exhibit 4.25 to the Company’s Annual Report on Form 20-F filed with the SEC on April 15, 2016). 4.6 Amendment Agreement No. 1 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated September 1.1 Certificate of Incorporation (incorporated herein by reference to Exhibit 1, 2016 relating to the Prepayment Agreement dated December 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333- 18, 2015 (incorporated herein by reference to Exhibit 4.27 to the 191068) filed with the SEC on September 9, 2013). Company’s Annual Report on Form 20-F filed with the SEC on April 11, 1.2 Memorandum of Association (incorporated herein by reference to 2017). Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File 4.7 Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I. No. 333-191068) filed with the SEC on September 9, 2013). Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December 1.3 Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the 16, 2016 relating to the Prepayment Agreement dated December Company’s Registration Statement on Form F-1 (File No. 333-191068) 18, 2015 (incorporated herein by reference to Exhibit 4.28 to the filed with the SEC on September 9, 2013). Company’s Annual Report on Form 20-F filed with the SEC on April 11, 1.4 Form of amended and restated bye-laws (incorporated herein by 2017). reference to Exhibit 3.4 to the Company’s Registration Statement on 4.8 Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I. Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December 2.2 Indenture, dated September 21, 2017, among GeoPark Limited, the 16, 2016 relating to the Prepayment Agreement dated December Bank of New York Mellon and Lord Securities Corporation (incorporated 18, 2015 (incorporated herein by reference to Exhibit 4.28 to the herein by reference to Exhibit 2.2 to the Company’s Annual Report on Company’s Annual Report on Form 20-F filed with the SEC on April 11, Form 20-F filed with the SEC on April 12, 2018). 2017). 2.3 Supplemental Indenture, dated as of January 28, 2019, among GeoPark 4.9 Asset Purchase Agreement between GeoPark Argentina Ltd. and Limited, Geopark Chile S.A., Geopark Colombia Coöperatie U.A. and the Pluspetrol S.A., dated December 18, 2017 (incorporated herein by Bank of New York Mellon. reference to Exhibit 4.23 to the Company’s Annual Report on Form 20-F 4.1 Special Contract for the Exploration and Exploitation of filed with the SEC on April 12, 2018). Hydrocarbons, Fell Block, dated April 29, 1997, among the Republic 4.10 Purchase and Sale Agreement for Crude Oil and Condensate of Fell of Chile, the Chilean Empresa Nacional de Petróleo (ENAP) and Block between Empresa Nacional del Petróleo (ENAP) and GeoPark Fell Cordex Petroleums Inc. (incorporated herein by reference to Exhibit S.p.A., dated April 21, 2017 (incorporated herein by reference to Exhibit 10.1 to the Company’s Registration Statement on Form F-1 (File No. 4.24 to the Company’s Annual Report on Form 20-F filed with the SEC 333-191068) filed with the SEC on September 9, 2013). on April 12, 2018). 4.2 Exploration and Production Contract regarding exploration for and 4.11 Sale and Purchase Agreement between LGI International Corp. and exploitation of hydrocarbons in the La Cuerva Block, dated April 16, Geopark Limited, dated November 28, 2018.* 2008, between the Colombian Agencia Nacional de Hidrocarburos and Hupecol Caracara LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Registration Statement on Form F-1 (File No. 333- 191068) filed with the SEC on September 9, 2013). 4.3 Exploration and Production Contract regarding exploration for and exploitation of hydrocarbons in the Llanos 34 Block, dated March 13, 2009, between the Colombian Agencia Nacional de Hidrocarburos and Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit 10.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 4.4 Contract for the sale and Purchase of Natural Gas 2017-2027 between GeoPark Fell SpA and Methanex Chile SpA dated March 31, 2017 150 GeoPark 20F No. Description 8.1 Subsidiaries of GeoPark Limited.* 12.1 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* 12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* 13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* 13.2 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* 15.1 Consent of Price Waterhouse & Co. S.R.L., Argentina.* 15.2 Consents of DeGolyer and MacNaughton to use its report.* 99.1 Reserves Report of DeGolyer and MacNaughton dated February 4, 2019, for reserves in Chile, Colombia, Peru, Argentina and Brazil as of December 31, 2018.* 101.INS XBRL Instance Document* 101.SCH XBRL Taxonomy Extension Schema Document* 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document* 101.DEF XBRL Taxonomy Extension Definition Linkbase Document* 101.LAB XBRL Taxonomy Extension Label Linkbase Document* 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document* * † Filed with this Annual Report on Form 20-F. Confidential treatment of certain provisions of these exhibits has been requested with the SEC. Omitted material for which confidential treatment has been requested has been filed separately with the SEC. GeoPark 151 Glossary of Oil and Natural Gas Terms The terms defined in this section are used throughout this annual report: grouped on or related to the same individual geological structural feature “appraisal well” means a well drilled to further confirm and evaluate the and/or stratigraphic condition. There may be two or more reservoirs in a field presence of hydrocarbons in a reservoir that has been discovered. that are separated vertically by intervening impervious strata, or laterally by “API” means the American Petroleum Institute’s inverted scale for denoting the local geologic barriers, or by both. Reservoirs that are associated by being “light” or “heaviness” of crude oils and other liquid hydrocarbons. in overlapping or adjacent fields may be treated as a single or common “bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein operational field. The geological terms structural feature and stratigraphic in reference to crude oil, condensate or natural gas liquids. condition are intended to identify localized geological features as opposed to “bcf” means one billion cubic feet of natural gas. the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. “bcm” means billion cubic meters. “formation” means a layer of rock which has distinct characteristics that differ “boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas from nearby rock. being equivalent to one barrel of oil. “mbbl” means one thousand barrels of crude oil, condensate or natural gas “boepd” means barrels of oil equivalent per day. liquids. “bopd” means barrels of oil per day. “mboe” means one thousand barrels of oil equivalent. “British thermal unit” or “btu” means the heat required to raise the temperature “mcf” means one thousand cubic feet of natural gas. of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. “Measurements” include: “basin” means a large natural depression on the earth’s surface in which • “m” or “meter” means one meter, which equals approximately 3.28084 feet; sediments generally brought by water accumulate. • “km” means one kilometer, which equals approximately 0.621371 miles; “CEOP” (Contrato Especial de Operación) means a special operating contract • “sq. km” means one square kilometer, which equals approximately 247.1 the Chilean signs with a company or a consortium of companies for the acres; exploration and exploitation of hydrocarbon wells • “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent “completion” means the process of treating a drilled well followed by the to approximately 0.15898 cubic meters; installation of permanent equipment for the production of natural gas or oil, • “boe” means one barrel of oil equivalent, which equals approximately or in the case of a dry hole, the reporting of abandonment to the appropriate 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of agency. natural gas to one barrel of oil; “developed acreage” means the number of acres that are allocated or • “cf” means one cubic foot; assignable to productive wells or wells capable of production. • “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, “developed reserves” are expected quantities to be recovered from existing respectively; wells and facilities. Reserves are considered developed only after the • “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, necessary equipment has been installed or when the costs to do so are respectively; relatively minor compared to the cost of a well. Where required facilities • “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, become unavailable, it may be necessary to reclassify developed reserves as respectively; and undeveloped. • “pd” means per day. “development well” means a well drilled within the proved area of an oil or gas “metric ton” or “MT” means one thousand kilograms. Assuming standard reservoir to the depth of a stratigraphic horizon known to be productive. quality oil, one metric ton equals 7.9 bbl. “dry hole” means a well found to be incapable of producing hydrocarbons “mmbbl” means one million barrels of crude oil, condensate or natural gas liquids. in sufficient quantities such that proceeds from the sale of such production “mmboe” means one million barrels of oil equivalent. exceed production expenses and taxes. “mmbtu” means one million British thermal units. “E&P Contract” means exploration and production contract “NYMEX” means The New York Mercantile Exchange. “economic interest” means an indirect participation interest in the net “net acres” means the percentage of total acres an owner has out of a revenues from a given block based on bilateral agreements with the particular number of acres, or a specified tract. An owner who has a 50% concessionaires. interest in 100 acres owns 50 net acres. “economically producible” means a resource that generates revenue that “productive well” means a well that is found to be capable of producing exceeds, or is reasonably expected to exceed, the costs of the operation. hydrocarbons in sufficient quantities such that proceeds from the sale of the “exploratory well” means a well drilled to find and produce oil or gas in production exceed production expenses and taxes. an unproved area, to find a new reservoir in a field previously found to be “prospect” means a potential trap which may contain hydrocarbons and is productive of oil or gas in another reservoir, or to extend a known reservoir. supported by the necessary amount and quality of geologic and geophysical Generally, an exploratory well is any well that is not a development well, a data to indicate a probability of oil and/or natural gas accumulation ready to service well, or a stratigraphic test well as those items are defined below. be drilled. The five required elements (generation, migration, reservoir, seal “field” means an area consisting of a single reservoir or multiple reservoirs all and trap) must be present for a prospect to work and if any of them fail neither 152 GeoPark 20F oil nor natural gas will be present, at least not in commercial volumes. “stratigraphic test well” means a drilling effort, geologically directed, to obtain “proved developed reserves” means those proved reserves that can be information pertaining to a specific geologic condition. Such wells customarily expected to be recovered through existing wells and facilities and by are drilled without the intention of being completed for hydrocarbon existing operating methods. production. This classification also includes tests identified as core tests and all “proved reserves” means estimated quantities of crude oil, natural gas, and types of expendable holes related to hydrocarbon exploration. Stratigraphic natural gas liquids which geological and engineering data demonstrate with test wells are classified as (i) exploratory-type, if not drilled in a proved area, or reasonable certainty to be economically recoverable in future years from (ii) development-type, if drilled in a proved area. known reservoirs under existing economic and operating conditions, as well “tcm” means trillion cubic meters. as additional reserves expected to be obtained through confirmed improved “undeveloped reserves” are quantities expected to be recovered through recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2). future investments: (1) from new wells on undrilled acreage in known “proved undeveloped reserves” means are those proved reserves that are accumulation, (2) from deepening existing wells to a different (but known) expected to be recovered from future wells and facilities, including future reservoir, (3) from infill wells that will increase recover, or (4) where a relatively improved recovery projects which are anticipated with a high degree of large expenditure ( e.g. , when compared to the cost of drilling a new well) certainty in reservoirs which have previously shown favorable response to is required to (a) recomplete an existing well or (b) install production or improved recovery projects. transportation facilities for primary or improved recovery projects. “reasonable certainty” means a high degree of confidence. “unit” means the joining of all or substantially all interests in a reservoir or “recompletion” means the process of re-entering an existing wellbore that field, rather than a single tract, to provide for development and operation is either producing or not producing and completing new reservoirs in an without regard to separate property interests. Also, the area covered by a attempt to establish or increase existing production. unitization agreement. “reserves” means estimated remaining quantities of oil and gas and related “wellbore” means the hole drilled by the bit that is equipped for oil or gas substances anticipated to be economically producible, as of a given date, by production on a completed well. Also called well or borehole. application of development projects to known accumulations. In addition, “working interest” means the right granted to the lessee of a property to there must exist, or there must be a reasonable expectation that there will explore for and to produce and own oil, gas, or other minerals. The working exist, a revenue interest in the production, installed means of delivering oil, interest owners bear the exploration, development, and operating costs on gas, or related substances to market, and all permits and financing required either a cash, penalty, or carried basis. to implement the project. “workover” means operations in a producing well to restore or increase “reservoir” means a porous and permeable underground formation production. containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. “royalty” means a fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance. “service well” means a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation, or injection for in-situ combustion. “shale” means a fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps. “spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres ( e.g. , 40-acre spacing, and is often established by regulatory agencies). “spud” means the very beginning of drilling operations of a new well, occurring when the drilling bit penetrates the surface utilizing a drilling rig capable of drilling the well to the authorized total depth. GeoPark 153 Signatures The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf. GEOPARK LIMITED By: /s/ James F. Park Name: James F. Park Title: Chief Executive Officer and Deputy Chairman Date: April 11, 2019 154 GeoPark 20F GeoPark 155 Consolidated Financial Statements As of and for the year ended 31 December 2018 Contents Report of Independent Registered Public Accounting Firm Consolidated Statement of Income Consolidated Statement of Comprehensive Income Consolidated Statement of Financial Position Consolidated Statement of Changes in Equity Consolidated Statement of Cash Flow Notes to the Consolidated Financial Statements 160 161 161 162 163 164 165 GeoPark 157 Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of GeoPark Limited Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated statement of financial position of GeoPark Limited and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of income and of comprehensive income, changes in equity and cash flows, for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. PRICE WATERHOUSE & CO. S.R.L. By (Partner) Fernando Alberto Rodríguez Autonomous City of Buenos Aires, Argentina March 6, 2019 We have served as the Company’s auditor since 2009. 158 GeoPark 20F Consolidated Statement of Income Amounts in US$ ´000 Note 2018 2017 2016 REVENUE Commodity risk management contracts Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful exploration efforts Impairment loss reversed for non-financial assets Other expenses OPERATING PROFIT (LOSS) Financial expenses Financial income Foreign exchange (loss) gain PROFIT (LOSS) BEFORE INCOME TAX Income tax expense PROFIT (LOSS) FOR THE YEAR Attributable to: Owners of the Company Non-controlling interest Earnings (Losses) per share (in US$) for profit (loss) attributable to owners of the Company. Basic Earnings (Losses) per share (in US$) for profit (loss) attributable to owners of the Company. Diluted Consolidated Statement of Comprehensive Income Amounts in US$ ´000 Profit (loss) for the year Other comprehensive income: Items that may be subsequently reclassified to profit or loss Currency translation differences Total comprehensive (loss) for the year Attributable to: Owners of the Company Non-controlling interest The notes on pages 8 to 79 are an integral part of these Consolidated Financial Statements. 7 8 9 12 13 14 20 20-36 601,161 16,173 (174,260) (13,951) (52,074) (4,023) (92,240) (26,389) 4,982 (2,887) 256,492 330,122 (15,448) (98,987) (7,694) (42,054) (1,136) (74,885) (5,834) - (5,088) 78,996 192,670 (2,554) (67,235) (10,282) (34,170) (4,222) (75,774) (31,366) 5,664 (1,344) (28,613) 15 15 15 (39,321) (53,511) (36,229) 3,059 (11,323) 208,907 2,016 (2,193) 25,308 2,128 13,872 (48,842) 17 (106,240) (43,145) (11,804) 102,667 (17,837) (60,646) 72,415 30,252 (24,228) 6,391 (49,092) (11,554) 19 19 1.19 (0.40) (0.82) 1.11 (0.40) (0.82) 2018 2017 2016 102,667 (17,837) (60,646) (4,401) 98,266 (512) 7,102 (18,349) (53,544) 68,014 30,252 (24,740) 6,391 (41,990) (11,554) GeoPark 159 Consolidated Statement of Financial Position Amounts in US$ ´000 ASSETS NON-CURRENT ASSETS Property, plant and equipment Prepaid taxes Other financial assets Deferred income tax asset Prepayments and other receivables TOTAL NON-CURRENT ASSETS CURRENT ASSETS Inventories Trade receivables Prepayments and other receivables Prepaid taxes Derivative financial instrument assets Other financial assets Cash and cash equivalents Assets held for sale TOTAL CURRENT ASSETS TOTAL ASSETS TOTAL EQUITY Equity attributable to owners of the Company Share capital Share premium Reserves Accumulated losses Attributable to owners of the Company Non-controlling interest TOTAL EQUITY LIABILITIES NON-CURRENT LIABILITIES Borrowings Provisions and other long-term liabilities Deferred income tax liability Trade and other payables TOTAL NON-CURRENT LIABILITIES CURRENT LIABILITIES Borrowings Derivative financial instrument liabilities Current income tax liabilities Trade and other payables Liabilities associated with assets held for sale TOTAL CURRENT LIABILITIES TOTAL LIABILITIES TOTAL EQUITY AND LIABILITIES The notes on pages XX to XX are an integral part of these Consolidated Financial Statements. 160 GeoPark 20F Note 2018 2017 20 22 25 18 24 23 24 24 22 25 25 25 35.2 26 35.1 27 28 18 29 27 25 29 35.2 557,170 517,403 3,275 10,570 31,793 219 3,823 22,110 27,636 235 603,027 571,207 9,309 16,215 9,489 45,170 27,539 898 127,727 23,286 259,633 862,660 5,738 19,519 7,518 26,048 - 21,378 134,755 - 214,956 786,163 60 237,840 111,809 61 239,191 129,606 (206,688) (283,933) 143,021 - 84,925 41,915 143,021 126,840 429,027 418,540 42,577 14,801 14,789 46,284 2,286 25,921 501,194 493,031 17,975 - 58,776 131,420 10,274 218,445 719,639 862,660 7,664 19,289 42,942 96,397 - 166,292 659,323 786,163 Consolidated Statement of Changes in Equity Amount in US$ ‘000 Equity at 1 January 2016 Comprehensive income: Loss for the year Currency translation differences Total Comprehensive profit (loss) for the year 2016 Transactions with owners: Share-based payment (Note 30) Repurchase of shares (Note 26) Dividends distribution to non-controlling interest Total 2016 Balances at 31 December 2016 Comprehensive income: (Loss) Profit for the year Currency translation differences Total Comprehensive (loss) profit for the year 2017 Transactions with owners: Share-based payment (Note 30) Dividends distribution to non-controlling interest Total 2017 Balances at 31 December 2017 Comprehensive income: Profit for the year Currency translation differences Total Comprehensive (loss) profit for the year 2018 Transactions with owners: Share-based payment (Note 30) Repurchase of shares (Note 26) Dividends distribution to non-controlling interest Transactions with non-controlling interest (Note 35.1) Total 2018 Balances at 31 December 2018 Attributable to owners of the Company (Accumulated Losses) Non- Share Share Other Translation Retained controlling Capital Premium Reserve Reserve Earnings 59 232,005 127,527 (4,511) (208,428) Interest 53,515 Total 200,167 - - - 1 - - 1 - - - 6,032 (1,991) - 4,041 - - - - - - - - (49,092) (11,554) (60,646) 7,102 7,102 - - 7,102 (49,092) (11,554) (53,544) - - - - (2,939) - - (2,939) 273 - (6,406) (6,133) 35,828 3,367 (1,991) (6,406) (5,030) 141,593 60 236,046 127,527 2,591 (260,459) - - - 1 - 1 - - - 3,145 - 3,145 - - - - - - - (24,228) 6,391 (17,837) (512) (512) - - (512) (24,228) 6,391 (18,349) - - - 754 - 754 175 (479) (304) 4,075 (479) 3,596 61 239,191 127,527 2,079 (283,933) 41,915 126,840 - - - - (1) - - (1) 60 - - - 449 (1,800) - - (1,351) 237,840 - - - - - - (13,396) (13,396) 114,131 - 72,415 30,252 (4,401) (4,401) - - 72,415 30,252 - - - - - 4,830 - - - 167 - (8,089) (64,245) 4,830 (72,167) (2,322) (206,688) - 102,667 (4,401) 98,266 5,446 (1,801) (8,089) (77,641) (82,085) 143,021 The notes on pages 8 to 79 are an integral part of these Consolidated Financial Statements. GeoPark 161 Consolidated Statement of Cash Flow Amounts in US$ ‘000 Note 2018 2017 2016 Cash flows from operating activities Profit (Loss) for the year Adjustments for: Income tax expense Depreciation Loss on disposal of property, plant and equipment Impairment loss reversed for non-financial assets Write-off of unsuccessful exploration efforts Accrual of borrowing’s interests Borrowings cancellation costs Amortization of other long-term liabilities Unwinding of long-term liabilities Accrual of share-based payment Foreign exchange loss (gain) Unrealized (gain) loss on commodity risk management contracts Income tax paid Changes in working capital Cash flows from operating activities – net Cash flows from investing activities Purchase of property, plant and equipment Acquisition of business Proceeds from disposal of long-term assets Cash flows used in investing activities – net Cash flows from financing activities Proceeds from borrowings Debt issuance costs paid Proceeds from cash calls from related parties Repurchase of shares Principal paid Interest paid Borrowings cancellation costs paid Dividends distribution to non-controlling interest Payments for transactions with non-controlling interest Cash flows (used in) from financing activities - net Net (decrease) increase in cash and cash equivalents Cash and cash equivalents at 1 January Currency translation differences Cash and cash equivalents at the end of the year Ending Cash and cash equivalents are specified as follows: Cash in bank and bank deposits Cash in hand Cash and cash equivalents The notes on pages 8 to 79 are an integral part of these Consolidated Financial Statements. 162 GeoPark 20F 102,667 (17,837) (60,646) 17 20-36 20 15 28 28 8 5 106,240 92,240 272 (4,982) 26,389 30,444 - (1,005) 3,505 5,446 11,323 (42,271) (67,704) (6,358) 256,206 43,145 74,885 190 - 5,834 28,879 17,575 (657) 2,779 4,075 2,193 13,300 (6,925) (25,278) 142,158 11,804 75,774 14 (5,664) 31,366 27,940 - (2,924) 2,693 3,367 (13,872) 3,068 (1,956) 11,920 82,884 (124,744) (105,604) (39,306) 35.3 35.2 (48,850) 9,000 - - - - (164,594) (105,604) (39,306) 36,017 425,000 - - (1,801) (15,073) (27,695) - (8,089) (81,000) (97,641) (6,029) 134,755 (999) 35.1 (6,683) 1,155 - (355,022) (27,688) (12,315) - 23,968 60,522 73,563 670 127,727 134,755 186 - 5,210 (1,991) (22,645) (25,490) - - (51,136) (7,558) 82,730 (1,609) 73,563 (479) (6,406) 127,707 134,734 73,551 20 21 12 127,727 134,755 73,563 Notes to Consolidated Financial Statements Note 1 General Information • Classification and Measurement of Share-based Payment Transactions – Amendments to IFRS 2 GeoPark Limited (the “Company”) is a company incorporated under the law • Annual Improvements 2014-2016 cycle of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1 • Interpretation 22 Foreign Currency Transactions and Advance Consideration Victoria Street, Hamilton HM11, Bermuda. The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and production for oil and gas • Annual Improvements to IFRS Standards 2015-2017 Cycle. reserves in Colombia, Chile, Brazil, Argentina and Peru. These Consolidated Financial Statements were authorized for issue by the classification and measurement of financial assets and financial liabilities, Board of Directors on 6 March 2019. derecognition of financial instruments, impairment of financial assets and IFRS 9 replaces the provisions of IAS 39 related to the recognition, The Group also elected to adopt the following amendments early: hedge accounting. Note 2 The adoption of IFRS 9 from 1 January 2018 resulted in changes in accounting Summary of significant accounting policies policies (see Note 2.16 and Note 2.18) and a reclassification of a measurement The principal accounting policies applied in the preparation of these category (see below), but no adjustments to the amounts recognized in the Consolidated Financial Statements are set out below. These policies have been Consolidated Financial Statements. consistently applied to the years presented, unless otherwise stated. 2.1 Basis of preparation On 1 January 2018, the Group classified money market funds for US$ 44,123,000 accounted within Cash and cash equivalents as of 31 December The Consolidated Financial Statements of GeoPark Limited have been 2017, as Financial assets at fair value through profit or loss that were prepared in accordance with International Financial Reporting Standards previously classified as Loans and receivables. No results were generated as a (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), consequence of this change. As of 31 December 2018, the Group holds money under the historical cost convention. market funds for US$ 53,794,000. The Consolidated Financial Statements are presented in thousands of United IFRS 15 replaces IAS 18 which covered contracts for goods and services and States Dollars (US$’000) and all values are rounded to the nearest thousand IAS 11 which covered construction contracts. The new standard is based on (US$’000), except in the footnotes and where otherwise indicated. the principle that revenue is recognized when control of a good or service transfers to a customer, so the notion of control replaces the existing notion of The preparation of financial statements in conformity with IFRS requires the risks and rewards. use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting The adoption of IFRS 15 from 1 January 2018 resulted in no changes in policies. The areas involving a higher degree of judgement or complexity, or accounting policies or adjustments to the amounts recognized in the areas where assumptions and estimates are significant to the Consolidated Consolidated Financial Statements. Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”. The adoption of the other amendments listed above did not have any impact on the amounts recognized in prior periods and are not expected to All the information included in these Consolidated Financial Statements significantly affect the current or future periods. corresponds to the Group, except where otherwise indicated. New standards, amendments and interpretations issued but not effective for the 2.1.1 Changes in accounting policy and disclosure financial year beginning 1 January 2018 and not early adopted. New and amended standards adopted by the Group The following standards have been adopted by the Group for the first time for in the recognition of almost all leases on the balance sheet. The standard the financial year beginning on or after 1 January 2018: removes the current distinction between operating and financing leases • IFRS 9 Financial Instruments and requires recognition of an asset (the right to use the leased item) and a financial liability to pay rentals for virtually all lease contracts. An optional • IFRS 15 Revenue from Contracts with Customers exemption exists for short-term and low-value leases. The accounting by • IFRS 16 Leases: will affect primarily the accounting by lessees and will result GeoPark 163 lessors will not significantly change. Some differences may arise as a result of Considering macroeconomic environment conditions, the performance the new guidance on the definition of a lease. of the operations, the US$ 425,000,000 debt fundraising completed in The Group has set up a project team by business unit which has reviewed total indebtedness matures in 2024, the Directors have formed a judgement, each business unit’s leasing arrangements over the last year in light of the at the time of approving the financial statements, that there is a reasonable new lease accounting rules in IFRS 16. The standard will affect primarily the expectation that the Group has adequate resources to meet all its obligations accounting for the Group’s operating leases. for the foreseeable future. For this reason, the Directors have continued September 2017, the Group’s cash position, and the fact that over 95% of its to adopt the going concern basis in preparing the Consolidated Financial As at the reporting date, the Group has non-cancellable operating lease Statements. commitments of US$ 69,938,000, see Note 32.3. Of these commitments, the Group expects to recognize right-of-use assets and lease liabilities, at nominal 2.3 Consolidation value, of approximately US$ 14,449,000 on 1 January 2019. The remaining Subsidiaries are all entities (including structured entities) over which the lease commitments, in accordance with IFRS 16, will be recognized on a Group has control. The Group controls an entity when the Group is exposed straight-line basis as expense in the Consolidated Statement of Income. to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the There will not be an impact on Adjusted EBITDA as a consequence of the entity. Subsidiaries are fully consolidated from the date on which control is adoption of this new standard. This measure is used to assess the performance transferred to the Group. They are deconsolidated from the date that control of the operating segments and is also considered for the calculation of the ceases. incurrence test covenants included in the indenture governing the Group’s main financial debt. Therefore, Management decided to modify the definition The Group applies the acquisition method to account for business of this measure since the adoption of IFRS 16 in 2019 in order to ensure combinations. The consideration transferred for the acquisition of a subsidiary comparability with previous periods. is the fair value of the assets transferred, the liabilities incurred by the former owners of the acquiree and the equity interests issued by the Group. The Operating cash flows will increase and financing cash flows decrease by consideration transferred includes the fair value of any asset or liability approximately US$ 4,000,000 as repayment of the principal portion of the resulting from a contingent consideration arrangement. Identifiable assets lease liabilities will be classified as cash flows from financing activities. acquired, and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The Group will apply the standard from its mandatory adoption date of 1 Acquisition-related costs are expensed as incurred. January 2019. The Group intends to apply the simplified transition approach and will not restate comparative amounts for the year prior to first adoption. The excess of the consideration transferred over the fair value of the Lease liability for property leases will be measured on transition at the identifiable net assets acquired is recorded as goodwill. If the total of present value of the remaining lease payments, discounted using the lessee’s consideration transferred is less than the fair value of the net assets of the incremental borrowing rate at the date of initial application. The right-of- subsidiary acquired in the case of a bargain purchase, the difference is use asset on transition (on a lease-by-lease basis) will be measure at an recognized directly in the income statement. amount equal to the lease liability (adjusted for any prepaid or accrued lease expenses). Intercompany transactions, balances and unrealized gains on transactions between the Group and its subsidiaries are eliminated. Unrealized losses are There are no other standards that are not yet effective and that would be also eliminated unless the transaction provides evidence of an impairment expected to have a material impact on the entity in the current or future of the asset transferred. Amounts reported in the financial statements of reporting periods and on foreseeable future transactions. subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group. 2.2 Going concern The Directors regularly monitor the Group’s cash position and liquidity risks 2.4 Segment reporting throughout the year to ensure that it has sufficient funds to meet forecast Operating segments are reported in a manner consistent with the internal operational and investment funding requirements. Sensitivities are run to reporting provided to the chief operating decision-maker. The chief operating reflect latest expectations of expenditures, oil and gas prices and other factors decision-maker, who is responsible for allocating resources and assessing to enable the Group to manage the risk of any funding short falls and/or performance of the operating segments, has been identified as the Executive potential debt covenant breaches. 164 GeoPark 20F Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance, Finance and People departments. This committee reviews the Group’s internal reporting 2.9 Financial results in order to assess performance and allocate resources. Management has Financial results include interest expenses, interest income, bank charges, determined the operating segments based on these reports. the amortization of financial assets and liabilities, and foreign exchange 2.5 Foreign currency translation gains and losses. The Group has capitalized the borrowing cost for wells and facilities that were initiated after 1 January 2009. The capitalization rate used 2.5.1. Functional and presentation currency to determine the amount of borrowing costs to be capitalized is the weighted The Consolidated Financial Statements are presented in US Dollars, which is average interest rate applicable to the Group’s general borrowings during the the Group’s presentation currency. year, which was 6.90% at year-end 2018 (6.90% at year-end 2017 and 7.98% in 2016). Amounts capitalized during the year amounted to US$ 257,507 (US$ Items included in the financial statements of each of the Group’s entities 610,841 in 2017 and US$ 254,950 in 2016). are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency 2.10 Property, plant and equipment of Group companies incorporated in Chile, Colombia, Peru and Argentina is Property, plant and equipment are stated at historical cost less depreciation the US Dollar, meanwhile for the Group´s Brazilian company the functional and impairment charges, if applicable. Historical cost includes expenditure currency is the local currency, which is the Brazilian Real. that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation. 2.5.2. Transactions and balances Foreign currency transactions are translated into the functional currency Oil and gas exploration and production activities are accounted for in using the exchange rates prevailing at the dates of the transactions. Foreign accordance with the successful efforts method on a field by field basis. The exchange gains and losses resulting from the settlement of such transactions Group accounts for exploration and evaluation activities in accordance with and from the translation at period-end exchange rates of monetary assets IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing and liabilities denominated in foreign currencies are recognized in the exploration and evaluation costs until such time as the economic viability Consolidated Statement of Income. of producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the 2.6 Joint arrangements Consolidated Statement of Income. Under IFRS 11 investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and Exploration and evaluation costs may include: license acquisition, geological obligations of each investor. and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of exploratory wells. No depreciation and/or amortization are charged during the The Group has assessed the nature of its joint arrangements and determined exploration and evaluation phase. Upon completion of the evaluation phase, them to be joint operations. The Group combines its share in the joint the prospects are either transferred to oil and gas properties or charged to operations individual assets, liabilities, results and cash flows on a line-by-line expense (exploration costs) in the period in which the determination is made, basis with similar items in its financial statements. depending whether they have discovered reserves or not. If not developed, 2.7 Revenue recognition exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is Revenue from the sale of crude oil and gas is recognized in the recoverable. Consolidated Statement of Income when control is transferred to the purchaser, and if the revenue can be measured reliably and is expected A charge of US$ 26,389,000 has been recognized in the Consolidated to be received. Revenue is shown net of VAT, discounts related to the sale Statement of Income within Write-off of unsuccessful exploration efforts (US$ and overriding royalties due to the ex-owners of oil and gas properties 5,834,000 in 2017 and US$ 31,366,000 in 2016). See Note 20. where the royalty arrangements represent a retained working interest in the property. See Note 32.1. 2.8 Production and operating costs All field development costs are considered construction in progress until they are finished and capitalized within oil and gas properties, and are subject to depreciation once completed. Such costs may include the acquisition and Production and operating costs are recognized in the Consolidated Statement installation of production facilities, development drilling costs (including dry of Income on the accrual basis of accounting. These costs include wages holes, service wells and seismic surveys for development purposes), project- and salaries incurred to achieve the revenue for the year. Direct and indirect related engineering and the acquisition costs of rights and concessions related costs of raw materials and consumables, rentals, leasing and royalties are also to proved properties. included within this account. GeoPark 165 Workovers of wells made to develop reserves and/or increase production the environment, the Group has considered it appropriate to periodically are capitalized as development costs. Maintenance costs are charged to the re-evaluate future costs of well-capping. The effects of this recalculation are Consolidated Statement of Income when incurred. included in the financial statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the Capitalized costs of proved oil and gas properties and production facilities and corresponding property, plant and equipment asset. machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable 2.11.2 Deferred Income reserves. The calculation of the “unit of production” depreciation takes into Relates to contributions received in cash from the Group’s clients to improve account estimated future finding and development costs and is based on the project economics of gas wells. The amounts collected are reflected as current year-end unescalated price levels. Changes in reserves and cost a deferred income in the balance sheet and recognized in the Consolidated estimates are recognized prospectively. Reserves are converted to equivalent Statement of Income over the productive life of the associated wells. The units on the basis of approximate relative energy content. depreciation of the gas wells that generated the deferred income is charged to Depreciation of the remaining property, plant and equipment assets (i.e. of the deferred income. The amounts used in 2017 correspond to the deferred furniture and vehicles) not directly associated with oil and gas activities has income related to the take-or-pay provision associated to gas sales in Brazil. been calculated by means of the straight-line method by applying such annual rates as required to write-off their value at the end of their estimated 2.12 Impairment of non-financial assets useful lives. The useful lives range between 3 years and 10 years. Assets that are not subject to depreciation and/or amortization (i.e.: the Consolidated Statement of Income simultaneously with the amortization Depreciation is allocated in the Consolidated Statement of Income as a Assets that are subject to depreciation and/or amortization are reviewed for separate line to better follow the performance of the business. impairment whenever events or changes in circumstances indicate that the exploration and evaluation assets) are tested annually for impairment. carrying amount may not be recoverable. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable An impairment loss is recognized for the excess of the asset’s carrying amount (see Impairment of non-financial assets in Note 2.12). amount over its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes 2.11 Provisions and other long-term liabilities of assessing impairment, assets are grouped at the lowest levels for which Provisions for asset retirement obligations, deferred income, restructuring there are separately identifiable cash flows (cash-generating units), generally obligations and legal claims are recognized when the Group has a present a licensed area. Non-financial assets other than goodwill that suffered legal or constructive obligation as a result of past events; it is probable that impairment are reviewed for possible reversal of the impairment at each an outflow of resources will be required to settle the obligation; and the reporting date. amount has been reliably estimated. Restructuring provisions comprise lease termination penalties and employee termination payments. No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the Provisions are measured at the present value of the expenditures expected to carrying value of the investment will be recoverable. be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to During 2018, impairment loss was reversed for US$ 4,982,000 (no impairment the obligation. The increase in the provision due to the passage of time is loss recognized or reversed in 2017 and impairment loss reversed for US$ recognized as financial expense. 5,664,000 in 2016). See Note 36. The write-offs are detailed in Note 20. 2.11.1 Asset Retirement Obligation 2.13 Lease contracts The Group records the fair value of the liability for asset retirement obligations All current lease contracts are considered to be operating leases on the basis in the period in which the wells are drilled. When the liability is initially that the lessor retains substantially all the risks and rewards related to the recorded, the Group capitalizes the cost by increasing the carrying amount of ownership of the leased asset. Payments related to operating leases and other the related long-lived asset. Over time, the liability is accreted to its present rental agreements are recognized in the Consolidated Income Statement value at each reporting period, and the capitalized cost is depreciated over on a straight-line basis over the term of the contract. The Group’s total the estimated useful life of the related asset. According to interpretations commitment relating to operating leases and rental agreements is disclosed and the application of current legislation, and on the basis of the changes in in Note 32.3. technology and the variations in the costs of restoration necessary to protect 166 GeoPark 20F Leases in which substantially all of the risks and rewards of ownership are temporary difference will not reverse in the foreseeable future. The Group is transferred to the lessee are classified as finance leases. Under a finance able to control the timing of dividends from its subsidiaries and hence does lease, the Group as lessor has to recognize an amount receivable equal to the not expect taxable profit. Hence deferred tax is recognized in respect of the aggregate of the minimum lease payments plus any unguaranteed residual retained earnings of overseas subsidiaries only if at the date of the statements value accruing to the lessor, discounted at the interest rate implicit in the of financial position, dividends have been accrued as receivable or a binding lease. 2.14 Inventories agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will revert in the foreseeable future. In the event that Inventories comprise crude oil and materials. these differences revert in total (e.g. dividends are declared and paid), the deferred tax liability which the Group would have to recognize amounts to Crude oil is measured at the lower of cost and net realizable value. Materials approximately US$ 11,400,000. are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition Deferred tax balances are provided in full, with no discounting. of transportation and similar costs. Cost is determined using the first-in, first- out (FIFO) method. 2.16 Non-current assets or disposal groups held for sale Non-current assets or disposal groups are classified as held for sale if their 2.15 Current and deferred income tax carrying amount will be recovered principally through a sale transaction rather The tax expense for the year comprises current and deferred tax. Tax is than through continuing use and a sale is considered highly probable. They recognized in the Consolidated Statement of Income. are measured at the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, assets arising from employee The current income tax charge is calculated on the basis of the tax laws benefits, financial assets and investment property that are carried at fair enacted or substantially enacted at the balance sheet date in the countries value and contractual rights under insurance contracts, which are specifically where the Company’s subsidiaries operate and generate taxable income. exempt from this requirement. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of An impairment loss is recognized for any initial or subsequent write-down of tax positions taken by the Group, through negotiations with relevant tax the asset or disposal group to fair value less costs to sell. A gain is recognized authorities or through litigation, can take several years to complete and, in for any subsequent increases in fair value less costs to sell of an asset or some cases, it is difficult to predict the ultimate outcome. disposal group, but not in excess of any cumulative impairment loss previously Deferred income tax is recognized, using the liability method, on temporary sale of the non-current asset or disposal group is recognized at the date of recognized. A gain or loss not previously recognized by the date of the differences arising between the tax bases of assets and liabilities and their derecognition. carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or Non-current assets (including those that are part of a disposal group) are not substantially enacted as of the balance sheet date and are expected to apply depreciated or amortized while they are classified as held for sale. Interest and when the related deferred income tax asset is realized, or the deferred income other expenses attributable to the liabilities of a disposal group classified as tax liability is settled. held for sale continue to be recognized. In addition, the Group has tax-loss carry-forwards in certain tax jurisdictions Non-current assets classified as held for sale and the assets of a disposal group that are available to be offset against future taxable profit. However, deferred classified as held for sale are presented separately from the other assets in the tax assets are recognized only to the extent that it is probable that taxable Consolidated Statement of Financial Position. The liabilities of a disposal group profit will be available against which the unused tax losses can be utilized. classified as held for sale are presented separately from other liabilities in the Management judgment is exercised in assessing whether this is the case. To Consolidated Statement of Financial Position. the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. 2.17 Financial assets Deferred income tax liabilities are provided on taxable temporary differences financial assets at fair value through profit or loss and fair value through other arising from investments in subsidiaries and joint arrangements, except comprehensive income. The classification depends on the Group’s business for deferred income tax liability where the timing of the reversal of the model for managing the financial assets and the contractual terms of the temporary difference is controlled by the Group and it is probable that the cash flows. The Group reclassifies debt investments when and only when its Financial assets are divided into the following categories: amortized cost; GeoPark 167 business model for managing those assets changes. 2.20 Cash and cash equivalents All financial assets not at fair value through profit or loss are initially Cash and cash equivalents includes cash in hand, deposits held at call with recognized at fair value, plus transaction costs. Transaction costs of financial banks, other short-term highly liquid investments with original maturities assets carried at fair value through profit or loss, if any, are expensed to profit of three months or less, and bank overdrafts. Bank overdrafts, if any, are or loss. shown within borrowings in the current liabilities section of the Consolidated Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all of the 2.21 Trade and other payables Statement of Financial Position. risks and rewards of ownership have been transferred. An assessment for Trade payables are obligations to pay for goods or services that have been impairment is undertaken at each balance sheet date. acquired in the ordinary course of the business from suppliers. Accounts Interest and other cash flows resulting from holding financial assets are less (or in the normal operating cycle of the business if longer). If not, they are payable are classified as current liabilities if payment is due within one year or recognized in the Consolidated Statement of Income when receivable, presented as non-current liabilities. regardless of how the related carrying amount of financial assets is measured. Amortized cost are non-derivative financial assets with fixed or determinable measured at amortized cost using the effective interest method. Trade payables are recognized initially at fair value and subsequently payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance 2.22 Derivatives sheet date. These are classified as non-current assets. These financial assets Derivative financial instruments are recognized in the statement of financial comprise trade receivables, prepayments and other receivables and cash position as assets or liabilities and initially and subsequently measured at fair value and cash equivalents in the Consolidated Statement of Financial Position. through profit and loss. They are presented as current assets or liabilities if they are They arise when the Group provides money, goods or services directly to a expected to be settled within 12 months after the end of the reporting period. debtor with no intention of trading the receivables. These financial assets are subsequently measured at amortized cost using the effective interest method, The mark-to-market fair value of the Group’s outstanding derivative instruments less provision for impairment, if applicable. is based on independently provided market rates and determined using standard Any change in their value through impairment or reversal of impairment within level 2 of the fair value hierarchy. Gains and losses arising from changes is recognized in the Consolidated Statement of Income. All of the Group’s in fair value are recognized in the Consolidated Statement of Income within financial assets are classified as amortized cost. Commodity risk management contracts. valuation techniques, including the impact of counterparty credit risk and are 2.18 Other financial assets For more information about derivatives please refer to Note 8. Non-current other financial assets include contributions made for environmental obligations according to a Colombian and Brazilian 2.23 Borrowings government request and are restricted for those purposes. Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of the instrument. Current other financial assets include short-term investments with original maturities up to twelve months and over three months. As of 31 December Borrowings are recognized initially at fair value, net of transaction costs 2017, they also included the security deposit granted in relation to the incurred. Borrowings are subsequently stated at amortized cost; any difference purchase of Argentinian assets (see Note 35.3). between the proceeds (net of transaction costs) and the redemption value is 2.19 Impairment of financial assets borrowings using the effective interest method. The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment methodology applied Direct issue costs are charged to the Consolidated Statement of Income on an depends on whether there has been a significant increase in credit risk. For accrual basis using the effective interest method. recognized in the Consolidated Statement of Income over the period of the trade receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be recognized from initial 2.24 Share capital recognition of the receivables. Equity comprises the following: • “Share capital” representing the nominal value of equity shares. • “Share premium” representing the excess over nominal value of the fair value 168 GeoPark 20F of consideration received for equity shares, net of expenses of the share The policy for managing these risks is set by the Board of Directors. Certain issuance. • “Other reserve” representing: risks are managed centrally, while others are managed locally following guidelines communicated from the corporate department. The policy for each – the equity element attributable to shares granted according to IFRS 2 but of the above risks is described in more detail below. not issued at year end or, – the difference between the proceeds from the transaction with non- Currency risk controlling interests received against the book value of the shares acquired In Colombia, Chile, Argentina and Peru the functional currency is the US Dollar. in the Chilean and Colombian subsidiaries. The fluctuation of the local currencies of these countries against the US Dollar • “Translation reserve” representing the differences arising from translation of does not impact the loans, costs and revenue held in US Dollars; but it does investments in overseas subsidiaries. impact the balances denominated in local currencies. Such is the case of the • “(Accumulated losses) Retained earnings” representing accumulated earnings prepaid taxes. and losses. 2.25 Share-based payment In Colombian, Chilean, Argentinean and Peruvian subsidiaries most of the balances are denominated in US Dollars, and since it is the functional currency The Group operates a number of equity-settled share-based compensation of the subsidiaries, there is no exposure to currency fluctuation except from plans comprising share awards payments to certain employees and other receivables or payables originated in local currency mainly corresponding to third-party contractors. Share-based payment transactions are measured in VAT and income tax. accordance with IFRS 2. Fair value of the stock option plan for employee or contractors services Argentina and Peru by seeking to balance local and foreign currency assets received in exchange for the grant of the options is recognized as an expense. and liabilities. However, tax receivables (VAT) seldom match with local The total amount to be expensed over the vesting period is determined currency liabilities. Therefore, the Group maintains a net exposure to them, by reference to the fair value of the options granted calculated using the except for what it is described below. The Group minimises the local currency positions in Colombia, Chile, Geometric Brownian Motion method. Non-market vesting conditions are included in assumptions about the currency fluctuation with respect to income tax balances in Colombia. number of options that are expected to vest. At each balance sheet date, the Consequently, the Group entered into a derivative financial instrument with a entity revises its estimates of the number of options that are expected to local bank in Colombia, for an amount equivalent to US$ 92,050,000, in order vest. It recognizes the impact of the revision to original estimates, if any, in to anticipate any currency fluctuation with respect to income taxes to be paid the Consolidated Statement of Income, with a corresponding adjustment to during the first half of 2019. The Group’s derivatives are accounted for as non- In December 2018, GeoPark decided to manage its future exposure to local equity. hedge derivatives as of 31 December 2018 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the results The fair value of the share awards payments is determined at the grant date of the periods in which they occur. Considering that the instrument was by reference of the market value of the shares and recognized as an expense subscribed by year-end, as of 31 December 2018 the impact was not material. over the vesting period. When the awards are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction Most of the Group’s assets held in those countries are associated with oil and costs are credited to share capital (nominal value) and share premium when gas productive assets. Those assets, even in the local markets, are generally the options are exercised. settled in US Dollar equivalents. Note 3 Financial Instruments-risk management During 2018, the Colombian Peso devalued by 9% (revalued by 1% in 2017 and 5% in 2016) against the US Dollar, the Chilean Peso devalued by 13% The Group is exposed through its operations to the following financial risks: (revalued by 8% in 2017 and devalued by 6% in 2016), the Argentine Peso • Currency risk • Price risk • Credit risk – concentration • Funding and liquidity risk • Interest rate risk • Capital risk management devalued by 102% (17% and 22% in 2017 and 2016) and the Peruvian Peso devalued by 4% (revalued by 4% in 2017 and 2% in 2016). If the Colombian Peso, the Chilean Peso, the Argentine Peso and the Peruvian Peso had each devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been lower by US$ 57,000 (post-tax loss higher by US$ 1,538,000 in 2017 and US$ 2,683,400 in 2016). GeoPark 169 In Brazil, the functional currency is the local currency, which is the Brazilian In Argentina, the realized oil prices for our production in the Neuquen Real. The fluctuation of the US Dollars against the Brazilian Real does not Basin follows the “Medanito” blend oil price reference, which has impact the loans, costs and revenues held in Brazilian Real; but it does impact traditionally been linked to ICE Brent adjusted by certain marketing the balances denominated in US Dollars. Such is the case of the provision and quality discounts based on API, delivery point and transport costs. for asset retirement obligation and the intercompany loan, which was fully Between May and November 2018, Medanito crude prices were capped cancelled in October 2018, reducing significantly the exposure to foreign industry-wide between US$ 65 per barrel and US$ 70 per barrel. Since currency fluctuation. The exchange loss generated by the Brazilian subsidiary December 2018, domestic prices have reconnected to the international during 2018 amounted to US$ 5,862,000 (loss of US$ 1,274,000 in 2017 and benchmark. gain of US$ 14,542,000 in 2016). During 2018, the Brazilian Real devalued by 17% against the US Dollar go from May to April. The price of the gas sold under these contracts (devalued by 2% in 2017 and revalued by 17% in 2016, respectively). If the depends mainly on domestic supply and demand and regulation affecting Gas sales in Argentina are carried out through annual contracts that Brazilian Real had devalued 10% against the US dollar, with all other variables the sector. held constant, post-tax profit for the year would have been lower by US$ 515,000 (post-tax loss higher by US$ 3,100,000 in 2017 and US$ 5,300,000 in If oil and methanol prices had fallen by 10% compared to actual prices 2016). during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year As currency rate changes between the US Dollar and the local currencies, the would have been lower by US$ 13,709,000 (post-tax loss higher by Group recognizes gains and losses in the Consolidated Statement of Income. US$ 10,423,000 in 2017 and US$ 23,655,000 in 2016). Price risk Since October 2016, GeoPark decided to manage part of the exposure The realized oil price for the Group is linked to US dollar denominated to crude oil price volatility using derivatives. The Group considers these crude oil international benchmarks. The market price of this commodity derivative contracts to be an effective manner of properly managing is subject to significant volatility and has historically fluctuated widely in commodity price risk. The price risk management activities mainly employ response to relatively minor changes in the global supply and demand for combinations of options and key parameters are based on forecasted oil, the geopolitical landscape, the economic conditions and a variety of production and budget price levels. GeoPark has also obtained credit additional factors. The main factors affecting realized prices for gas sales lines from industry leading counterparties to minimize the potential cash vary across countries with some closely linked to international references exposure of the derivative contracts (see Note 8). while others are more domestically driven. In Colombia, the realized oil price is linked to the Vasconia crude reference The Group’s credit risk relates mainly to accounts receivable where the price, a marker broadly used in the Llanos basin, adjusted for certain credit risks correspond to the recognized values of commodities sold. marketing and quality discounts based on, among other things, API, GeoPark considers that there is no significant risk associated to the Group’s viscosity, sulphur content, water content, delivery point and transport major customers and hedging counterparties. Credit risk – concentration costs. In Colombia, during 2018, the Colombian subsidiary made 99% of the oil In Chile, the oil price is based on Dated Brent minus certain marketing and sales to Trafigura (one of the world’s leading independent commodity quality discounts such as, API, sulphur content and others. trading and logistics houses), with Trafigura accounting for 82% of the GeoPark has signed a long-term Gas Supply Contract with Methanex in term contract with Trafigura in December 2018, GeoPark begun diversifying Chile. The price of the gas sold under this contract is determined by a its client base in Colombia, allocating sales on a competitive basis to formula that considers a basket of international methanol prices, including industry leading participants including traders and other producers. The US Gulf methanol spot barge prices, methanol spot Rotterdam prices and contracts extend through 2019 with no longer term delivery commitments consolidated revenue for the same period. With the expiration of our long- spot prices in Asia. in place. Delivery points include wellhead and other locations on the Colombian pipeline system. GeoPark manages its counterparty credit risk In Brazil, prices for gas produced in the Manati Field are based on a long- associated to sales contracts by including early payment conditions to term off-take contract with Petrobras. The price of gas sold under this minimize the exposure. contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Indice Geral All the oil produced in Chile as well as the gas produced by TdF blocks (3% de Preços do Mercado), or IGPM. 170 GeoPark 20F of the consolidated revenue, 5% in 2017 and 10% in 2016) is sold to ENAP, test covenants related to compliance with certain thresholds of Net Debt to the State-owned oil and gas company. In Chile, most of gas production is Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply sold to the local subsidiary of Methanex, a Canadian public company (3% of with the incurrence test covenants does not trigger an event of default. the consolidated revenue, 5% in 2017 and 9% in 2016). However, this situation may limit the Group’s capacity to incur additional In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the date of these Consolidated Financial Statements, the Group is in compliance State-owned company, which is the operator of the Manati Field (5% of the with all the indenture’s provisions and covenants. indebtedness, as specified in the indenture governing the Notes. As of the consolidated revenue, 10% in 2017 and 15% in 2016). The most significant funding transactions executed during 2018 and 2017 In Argentina, all the gas produced is sold to Grupo Albanesi, a leading include: Argentine privately-held conglomerate focused on the energy market that offers natural gas, power supply and transport services to its customers. In October 2018, the Brazilian subsidiary executed a loan agreement with GeoPark has an annual agreement in effect from May 2018 through April Banco Santander for Brazilian Real 77,640,000 (equivalent to US$ 20,000,000 2019. Gas sales in Argentina account for 1% of the consolidated revenues. at the moment of the loan execution) to repay an existing US$-denominated The oil sales in Argentina are diversified across clients and delivery points: The interest rate applicable to this loan is CDI plus 2.25% per annum. “CDI” i) 30% of the oil produced in Argentina (2% of the consolidated revenue) (Interbank certificate of deposit) represents the average rate of all inter-bank is sold locally in Neuquen, delivered at well-head; and ii) 70% of the oil overnight transactions in Brazil. The principal and the interest are paid semi- produced in Argentina (3% of the consolidated revenue) is sold to major annually, with final maturity in October 2020. intercompany loan to GeoPark Latin America Limited - Agencia en Chile. Argentinean refineries, delivered via pipeline. GeoPark manages the counterparty credit risk associated to sales contracts by limiting payment In April 2018, the Colombian subsidiary executed an offtake and prepayment terms offered to minimize the exposure. agreement with Trafigura, one of its customers. The prepayment agreement provided GeoPark with access to up to US$ 25,000,000 in the form of prepaid The forementioned companies all have a good credit standing and despite future oil sales. The availability period for the prepayment agreement expires the concentration of the credit risk, the Directors do not consider there to on 31 March 2019. As of the date of these Consolidated Financial Statements, be a significant collection risk. GeoPark has not withdrawn any amount from this prepayment agreement. Since October 2016, the Group has executed oil prices hedges via over-the- In September 2017, the Company successfully placed US$ 425,000,000 Notes. counter derivatives. Should oil prices drop, the Group could stand to collect These Notes carry a coupon of 6.50% per annum and their final maturity will from its counterparties under the derivative contracts. The Group’s hedging be 21 September 2024. The net proceeds from the Notes were used by the counterparties are leading financial institutions and trading companies, Group to fully repay the 7.50% senior secured Notes due 2020 and for general therefore the Directors do not consider there to be a significant collection corporate purposes, including capital expenditures and to repay other existing risk. See disclosure in Notes 8 and 25. Funding and Liquidity risk indebtedness. Interest rate risk The Group’s interest rate risk arises from long-term borrowings issued at variable rates, which expose the Group to interest rate risk. In the past, the Group was able to raise capital through different sources of funding including equity, strategic partnerships and financial debt. During The Group does not face interest rate risk on its US$ 425,000,000 Notes which 2017, the Group placed US$ 425,000,000 Notes (see Note 27). carry a fixed rate coupon of 6.50% per annum. Consequently, the accruals and interest payment are not substantially affected by the market interest rate The Group is positioned at the end of 2018 with a cash balance of US$ changes. 127,727,000 and over 95% of its total indebtedness matures in 2024. In addition, the Group has a large portfolio of attractive and largely discretional At 31 December 2018, the outstanding long-term borrowing affected by projects - both oil and gas - in multiple countries with over 39,000 boepd in a variable rate amounted to US$ 19,750,000, representing 4.5% of total production at year end. This scale and positioning permit the Group to protect borrowings. It corresponds to a loan from Santander Bank taken by the its financial condition and selectively allocate capital to the optimal projects Brazilian subsidiary that has a floating interest rate based on CDI (Interbank subject to prevailing macroeconomic conditions. certificate of deposit), which represents the average rate of all inter-bank The Indenture governing the Company Notes 2024 includes incurrence overnight transactions in Brazil. GeoPark 171 The Group analyses its interest rate exposure on a dynamic basis. Various Statements are noted below: scenarios are simulated taking into consideration refinancing, renewal of existing positions, alternative financing and hedging. Based on these • Cash flow estimates for impairment assessments of non-financial scenarios, the Group calculates the impact on profit and loss of a defined assets require assumptions about two primary elements: future prices interest rate. For each simulation, the same interest rate is used for all and reserves. Estimates of future prices require significant judgments currencies. The scenarios are run only for liabilities that represent the major about highly uncertain future events. Historically, oil and gas prices interest-bearing positions. have exhibited significant volatility. The Group’s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst At 31 December 2018, if 1% is added to interest rates on currency- industry analysts and internal assessments. Estimates of future cash flows denominated borrowings with all other variables held constant, post-tax are generally based on assumptions of long-term prices and operating and profit for the year would have been lower by US$ 21,000 (no exposure to development costs. fluctuations in the interest rate in 2017 and post-tax loss higher by US$ 467,000 in 2016). Capital risk management Given the significant assumptions required and the possibility that actual conditions may differ, management considers the assessment of impairment to be a critical accounting estimate (see Note 36). The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for The process of estimating reserves is complex. It requires significant shareholders and benefits for other stakeholders and to maintain an optimal judgements and decisions based on available geological, geophysical, capital structure to reduce the cost of capital. engineering and economic data. The estimation of economically Consistent with others in the industry, the Group monitors capital on the basis was performed based on the Reserve Report as of 31 December 2018 of the gearing ratio. This ratio is calculated as net debt divided by total capital. prepared by DeGolyer and MacNaughton, an independent international Net debt is calculated as total borrowings (including ‘current and non-current consultancy to the oil and gas industry based in Dallas. It incorporates borrowings’ as shown in the consolidated balance sheet) less cash and cash many factors and assumptions including: equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated balance sheet plus net debt. – expected reservoir characteristics based on geological, geophysical and recoverable oil and natural gas reserves and related future net cash flows The Group’s strategy, due to the market conditions prevailing during the last – future production rates based on historical performance and expected years and the growth strategy of the Group, is to keep the gearing ratio within future operating and investment activities; a 60% to 80% range. – future oil and gas prices and quality differentials; – assumed effects of regulation by governmental agencies; and The gearing ratios at 31 December 2018 and 2017 were as follows: – future development and operating costs. engineering assessments; Amounts in US$ ‘000 Net Debt Total Equity Total Capital Gearing Ratio Note 4 Accounting estimates and assumptions 2018 319,275 143,021 462,296 69% 2017 Management believes these factors and assumptions are reasonable based 291,449 on the information available to them at the time of preparing the estimates. 126,840 However, these estimates may change substantially as additional data from 418,289 ongoing development activities and production performance becomes available 70% and as economic conditions impacting oil and gas prices and costs change. • The Group adopts the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding Estimates and assumptions are used in preparing the financial statements. whether an exploration and evaluation asset should continue to be carried Although these estimates are based on management’s best knowledge forward as such when insufficient information exists. This assessment is made of current events and actions, actual results may differ. Estimates and on a quarterly basis considering the advice from qualified experts. judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed • Oil and gas assets held in property plant and equipment are mainly to be reasonable under the circumstances. depreciated on a unit of production basis at a rate calculated by reference to The key estimates and assumptions used in these Consolidated Financial of developing and extracting those reserves. Future development costs are proven and probable reserves and incorporating the estimated future cost 172 GeoPark 20F estimated using assumptions as to the numbers of wells required to produce Amounts in US$ ‘000 2018 2017 2016 those reserves, the cost of the wells and future production facilities. (Decrease) Increase in asset • Obligations related to the abandonment of wells once operations are (Decrease) Increase in provisions terminated may result in the recognition of significant obligations. Estimating for other long-term liabilities (60) the future abandonment costs is difficult and requires management to Purchase of property, plant and equipment 1,100 2,053 11,759 3,468 (4,657) make estimates and judgments because most of the obligations are many years in the future. Technologies and costs are constantly changing as well Changes in working capital shown in the Consolidated Statement of Cash retirement obligation (4,355) 5,943 1,195 as political, environmental, safety and public relations considerations. The Flow are disclosed as follows: Group has adopted the following criterion for recognizing well plugging and abandonment related costs: The present value of future costs necessary for Amounts in US$ ‘000 well plugging and abandonment is calculated for each area at the present Increase in Prepaid taxes value of the estimated future expenditure. The liabilities recognized are based Decrease (Increase) in Inventories upon estimated future abandonment costs, wells subject to abandonment, Decrease (Increase) in Trade receivables time to abandonment, and future inflation rates. Decrease (Increase) in Prepayments and 2018 2017 (36,716) (14,802) 511 3,423 (2,031) (1,344) 2016 (2,351) 466 (4,811) • From time to time, the Group may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental, safety and health matters. Customer advance (repayments) payments (a) Security deposit utilised For example, from time to time, the Group receives notice of environmental, (granted) (Note 35.3) health and safety violations. Based on what the Management of the Group Increase in Trade and other payables currently knows, it is not expected any material impact on the financial (10,000) (10,000) 20,000 15,600 20,169 (15,600) 27,122 - 374 (6,358) (25,278) 11,920 other receivables and Other assets 655 (8,623) (1,758) statements. Note 5 Consolidated Statement of Cash Flow (a) In December 2015, the Colombian subsidiary entered into a prepayment agreement with Trafigura under which GeoPark sells and deliver a portion of its Colombian crude oil production. Funds committed were repaid by the The Consolidated Statement of Cash Flow shows the Group’s cash flows for the Group on a monthly basis through future oil deliveries until December 2018. year for operating, investing and financing activities and the change in cash and cash equivalents during the year. Note 6 Segment information Cash flows from operating activities are computed from the results for the Operating segments are reported in a manner consistent with the internal year adjusted for non-cash operating items, changes in net working capital, reporting provided to the chief operating decision-maker. The chief operating and corporate tax. Income tax paid is presented as a separate item under decision-maker, who is responsible for allocating resources and assessing operating activities. performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the CEO, COO, CFO and managers Cash flows from investing activities include payments in connection with the in charge of the Geoscience, Operations, Corporate Governance, Finance and purchase and sale of property, plant and equipment and cash flows relating to People departments. This committee reviews the Group’s internal reporting the purchase and sale of enterprises to third parties, if any. in order to assess performance and to allocate resources. Management has determined the operating segments based on these reports. The committee Cash flows from financing activities include changes in equity, and proceeds considers the business from a geographic perspective. from borrowings and repayment of loans. Cash and cash equivalents include bank overdraft and liquid funds with a term based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit The Executive Committee assesses the performance of the operating segments of less than three months. for the period before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful The following chart describes non-cash transactions related to the efforts, accrual of share-based payment, unrealized result on commodity risk Consolidated Statement of Cash Flow: management contracts and other non-recurring events. Operating Netback is equivalent to Adjusted EBITDA before cash expenses included in Administrative, Geological and Geophysical and Other operating expenses. Other information provided, except as noted below, to the Executive Committee is measured in a manner consistent with that in the financial statements. GeoPark 173 Segment areas (geographical segments): Amounts in US$ ‘000 2018 Revenue Sale of crude oil Sale of gas Realized loss on commodity risk management contracts Production and operating costs Royalties Transportation costs Share-based payment Other operating costs Operating profit (loss) Operating netback Adjusted EBITDA Depreciation Reversal (recognition) of impairment losses Write-off Total assets Employees (average) Employees at year end Amounts in US$ ‘000 2017 Revenue Sale of crude oil Sale of gas Realized loss on commodity risk management contracts Production and operating costs Royalties Transportation costs Share-based payment Other operating costs Operating profit (loss) Operating netback Adjusted EBITDA Depreciation Write-off Total assets Employees (average) Employees at year end 174 GeoPark 20F Colombia Chile Brazil Argentina Peru Corporate Total 497,870 496,341 1,529 37,359 17,402 19,957 (26,098) - (118,533) (21,899) (62,710) (1,258) (461) (54,104) 309,357 352,672 319,447 (1,473) (1,250) (226) (18,950) (29,139) 15,153 8,784 30,053 1,198 28,855 - (8,785) (2,820) - (37) (5,928) 4,370 21,306 17,908 35,879 30,549 5,330 - (25,043) (4,833) (120) (154) (19,936) (6,739) 8,527 4,576 - - - - - - - - - - - - - - - - - - (4,529) (16,828) - - (7,077) (13,082) 601,161 545,490 55,671 (26,098) (174,260) (71,836) (2,628) (878) (98,918) 256,492 397,658 330,556 (42,721) (28,203) (10,395) (10,640) (245) (36) (92,240) 11,531 (17,665) 383,450 (6,549) (6,121) 276,449 182 178 101 100 - (2,020) 70,424 12 12 - (583) 87,259 121 137 - - - - 35,817 9,261 4,982 (26,389) 862,660 27 28 2 2 445 457 Colombia Chile Brazil Argentina Peru Corporate Total 263,076 262,309 767 (2,148) (66,913) (24,236) (1,678) (248) (40,751) 116,290 194,013 168,303 (40,010) (1,625) 288,429 32,738 15,873 16,865 - (20,999) (1,314) (1,211) (170) (18,304) (19,675) 11,222 4,070 34,238 910 33,328 - (10,737) (3,134) - (39) (7,564) 4,434 23,540 20,166 (23,730) (10,809) (546) 301,931 (2,978) 91,604 70 70 - - (338) (13) (80) - (245) (3,430) (467) (2,183) (159) (685) - - - - - - - - - - - - - - - - - - (3,850) (14,773) - - (3,505) (11,075) (139) - (38) - 30,924 22,099 51,176 330,122 279,162 50,960 (2,148) (98,987) (28,697) (2,969) (457) (66,864) 78,996 228,308 175,776 (74,885) (5,834) 786,163 164 180 102 102 12 12 88 92 13 19 - - 379 405 Amounts in US$ ‘000 2016 Revenue Sale of crude oil Sale of gas Realized gain on commodity risk management contracts Production and operating costs Royalties Transportation costs Share-based payment Other operating costs Operating profit (loss) Operating netback Adjusted EBITDA Depreciation Reversal of impaiment losses Write-off Total assets Employees (average) Employees at year end Colombia Chile Brazil Argentina Peru Corporate Total 126,228 125,731 497 514 36,723 18,774 17,949 - (36,607) (22,169) (7,281) (1,111) (413) (27,802) 31,463 87,523 66,921 (1,495) (1,170) (138) (19,366) (44,969) 13,696 5,159 29,719 688 29,031 - (8,459) (2,721) - (71) (5,667) (645) 21,356 17,487 - - - - - - - - - - - - - - - - - - - - - - - - - - - 370 (378) 1,848 (3,147) (11,685) 41 (91) (2,607) (10,487) 192,670 145,193 47,477 514 (67,235) (11,497) (2,281) (622) (52,835) (28,613) 122,147 78,321 (31,148) (31,355) (12,974) (150) (130) (17) (75,774) 5,664 (7,394) 182,784 - (19,389) 317,969 138 146 102 102 - (4,583) 99,904 10 10 - - - - - - 6,071 5,020 28,792 5,664 (31,366) 640,540 80 77 11 10 - - 341 345 Approximately 78% of capital expenditure was incurred by Colombia (76% in 2017 and 67% in 2016), 6% was incurred by Chile (10% in 2017 and 20% in 2016), 2% was incurred by Brazil (3% in 2017 and 9% in 2016), 7% was incurred by Argentina (8% in 2017 and 4% in 2016) and 7% was incurred by Peru ( 3% in 2017 and nil in 2016). A reconciliation of total Operating netback to total profit (loss) before income Note 7 tax is provided as follows: Amounts in US$ ‘000 Operating netback Administrative expenses Geological and geophysical expenses Adjusted EBITDA Revenue 2018 2017 2016 Amounts in US$ ‘000 397,658 228,308 122,147 Sale of crude oil (48,028) (19,074) (38,937) (13,595) (32,323) Sale of gas (11,503) 2018 545,490 55,671 2017 279,162 50,960 2016 145,193 47,477 601,161 330,122 192,670 for reportable segments 330,556 175,776 78,321 Note 8 Unrealized gain (loss) on commodity Commodity risk management contracts risk management contracts Depreciation (a) Share-based payment Impairment and write-off of unsuccessful efforts Others (b) Operating profit (loss) Financial expenses Financial income Foreign exchange (loss) profit 42,271 (92,240) (5,446) (21,407) 2,758 256,492 (39,321) 3,059 (11,323) (13,300) (74,885) (4,075) (5,834) 1,314 78,996 (53,511) 2,016 (2,193) (3,068) The Group has entered into derivative financial instruments to manage its (75,774) exposure to oil price risk. These derivatives are zero-premium collars or zero- (3,367) premium 3 ways (put spread plus call), and were placed with major financial institutions and commodity traders. The Group entered into the derivatives (25,702) under ISDA Master Agreements and Credit Support Annexes, which provide 977 credit lines for collateral posting thus alleviating possible liquidity needs (28,613) under the instruments and protect the Group from potential non-performance (36,229) risk by its counterparties. The Group’s derivatives are accounted for as non- 2,128 hedge derivatives as of 31 December 2018 and therefore all changes in the fair 13,872 values of its derivative contracts are recognised as gains or losses in the results Profit (Loss) before tax (a) Net of capitalized costs for oil stock included in Inventories. (b) Includes allocation to capitalized projects. 208,907 25,308 (48,842) of the periods in which they occur. GeoPark 175 The following table presents the Group’s derivative contracts in force as of 31 December 2018: Period 1 April 2018 - 31 December 2018 1 April 2018 - 31 December 2018 1 July 2018 - 31 March 2019 1 July 2018 - 31 March 2019 1 October 2018 - 30 June 2019 1 October 2018 - 30 June 2019 1 October 2018 - 30 June 2019 1 January 2019 - 30 September 2019 1 January 2019 - 30 September 2019 Reference ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT Type Volume bbl/d Price US$/bbl Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium Collar Zero Premium Collar 3,000 1,000 2,000 2,000 3,700 1,000 1,300 2,000 3,000 45.00-55.00 Put 77.15 Call 45.00-55.00 Put 77.50 Call 50.00-60.00 Put 97.00 Call 50.00-60.00 Put 97.05 Call 55.00-65.00 Put 90.00 Call 55.00-65.00 Put 90.10 Call 55.00-65.00 Put 90.50 Call 65.00 Put 92.50 Call 65.00 Put 92.26 Call The table below summarizes the gain (loss) on the commodity risk management contracts: Realized (loss) gain on commodity risk management contracts Unrealized gain (loss) on commodity risk management contracts 2018 (26,098) 42,271 16,173 2017 (2,148) (13,300) (15,448) 2016 514 (3,068) (2,554) Note 10 Depreciation 2016 Amounts in US$ ‘000 13,160 Oil and gas properties 2,137 Production facilities and machinery 8,722 Furniture, equipment and vehicles 622 Buildings and improvements 2018 72,130 17,958 1,579 996 2017 57,725 14,558 1,948 844 2016 61,080 10,788 2,702 920 11,497 8,283 2,281 3,868 2,222 6,300 1,687 1,082 5,374 Depreciation of property, plant and equipment (a) 92,663 75,075 75,490 Related to: Productive assets Administrative assets Depreciation total (a) 90,088 2,575 92,663 72,283 2,792 75,075 71,868 3,622 75,490 (a) Depreciation without considering capitalized costs for oil stock included in Inventories. 2017 14,722 3,116 11,901 457 28,697 11,902 2,969 5,818 2,591 6,069 2,377 1,213 7,155 98,987 67,235 Total Note 9 Production and operating costs Amounts in US$ ‘000 Well and facilities maintenance Operation and maintenance Staff cost (Note 11) Share-based payment (Notes 11) Royalties Consumables Transportation costs Equipment rental Safety and Insurance costs Gas plant costs Field camp Non operated blocks costs Other costs 2018 20,262 7,756 17,725 878 71,836 17,444 2,628 9,317 3,878 5,967 2,959 1,327 12,283 174,260 176 GeoPark 20F Note 11 Staff costs and Directors Remuneration Number of employees at year end Amounts in US$ ‘000 Wages and salaries Share-based payments (Note 30) Social security charges Director’s fees and allowance Recognised as follows: Production and operating costs Geological and geophysical expenses Administrative expenses Board of Directors’ and key managers’ remuneration Salaries and fees Share-based payments Other benefits in kind 2018 457 2017 405 2016 345 52,644 41,775 33,922 5,446 7,464 2,876 4,075 5,364 3,458 3,367 3,792 2,088 68,430 54,672 43,169 18,603 15,527 34,300 68,430 12,358 11,026 31,288 54,672 9,344 10,439 23,386 43,169 12,452 2,918 272 9,674 2,322 287 15,642 12,283 7,337 1,211 112 8,660 Directors’ Remuneration Gerald O’Shaughnessy James F. Park Pedro Aylwin (a) Juan Cristóbal Pavez (b) Carlos Gulisano (c) Robert Bedingfield (d) Jamie Coulter Constantine Papadimitriou Executive Directors’ Executive Directors’ Non-Executive Director Fees Paid in Cash Equivalent Total Fees (in US$) Bonus (in US$) Directors’ Fees (in US$) Shares (No. of Shares) Remuneration (in US$) 400,000 800,000 26,000 - - - - - - 695,506 - - - - - - - - - 110,000 110,000 110,000 75,000 40,000 - - - 7,596 7,596 7,596 7,596 2,761 400,000 1,495,506 26,000 210,000 210,000 210,000 175,000 90,000 a Pedro E. Aylwin has a service contract that provides for him to act as Director of Legal and Governance. b Compensation Committee Chairman. c Technical Committee Chairman. d Audit Committee Chairman. On 2 January 2019, 439,075 shares were issued to Directors as a consequence of the vesting of the Value Creation Plan (”VCP”). See Note 30. GeoPark 177 Note 12 Geological and geophysical expenses Note 15 Financial results Amounts in US$ ‘000 Staff costs (Note 11) Share-based payment (Notes 11) Allocation to capitalized project Other services Note 13 Administrative expenses Amounts in US$ ‘000 Staff costs (Note 11) Share-based payment (Notes 11) Consultant fees Office expenses Travel expenses Director’s fees and allowance (Note 11) Communication and IT costs Allocation to joint operations Other administrative expenses 2018 15,005 522 (5,645) 4,069 13,951 2018 27,378 4,046 7,427 3,021 3,730 2,876 2,395 (7,774) 8,975 52,074 2017 10,525 501 (6,402) 3,070 7,694 2017 24,713 3,117 5,120 2,506 2,772 3,458 2,109 (7,646) 5,905 42,054 2016 9,541 Amounts in US$ ‘000 Financial expenses 898 Interest and amortization (2,119) of debt issue costs 1,962 Interest with related parties 10,282 Less: amounts capitalized on qualifying assets Borrowings cancellation costs Bank charges and other financial results Unwinding of long-term liabilities 2016 19,451 Financial income Interest received Foreign exchange gains and losses Foreign exchange (loss) gain 1,847 3,894 2,217 1,717 2,088 2,013 2018 2017 2016 (28,955) (1,606) (27,823) (2,224) (28,984) (1,587) 258 - (5,513) (3,505) 611 (17,575) (3,721) (2,779) 255 - (3,220) (2,693) (39,321) (53,511) (36,229) 3,059 3,059 2,016 2,016 2,128 2,128 (11,323) (11,323) (2,193) (2,193) 13,872 13,872 (4,365) Total Financial results (47,585) (53,688) (20,229) 5,308 34,170 Note 16 Tax reforms Colombia 2018 2,638 1,385 4,023 2017 864 272 1,136 In December 2018, a tax reform was enacted in Colombia. The approved legislation included significant changes in the corporate income tax but also in other taxes and in tax related matters (as procedural rules and special 2016 3,559 663 regimes). This tax reform was effective 1 January 2019. 4,222 The new legislation includes a progressive reduction of the general corporate income tax rate, previously established at 40% for 2017 and 37% for 2018, as follows: • 33% in 2019 • 32% in 2020 • 31% in 2021 • 30% in 2022 and onwards. Other changes that could affect the Group are the following: • The withholding tax rate on dividends for non-resident shareholders was increased from 5% to 7.5%. • The withholding tax rates applicable on payments to non-residents on behalf of consultancy, technical services, technical assistance, software and interests on loans of less than one year were increased from 15% to 20% (for loans with maturity exceeding one year, the 15% rate remained unchanged). • The withholding tax rate applicable on payments to entities resident of countries considered to be tax havens, non-cooperative or to grant a Note 14 Selling expenses Amounts in US$ ‘000 Transportation Selling taxes and other 178 GeoPark 20F preferential tax regime was increased from 15% to the corporate income Note 17 tax rate (33 % for 2019, 32% for 2020, 31% for 2021 and 30% for 2022 and Income tax onwards). • The deduction of interest attributed to a permanent establishment in Amounts in US$ ‘000 Colombia on behalf of its head office debt was limited to interest that had Current tax 2018 2017 2016 (101,456) (48,449) (12,359) been subject to Colombian withholding tax. Deferred income tax (Note 18) (4,784) 5,304 555 • Regarding thin capitalization for income tax purposes, the maximum amount of debt which interest can be deducted was reduced from 3 to 2 (106,240) (43,145) (11,804) times the net equity of the taxpayer as of 31 December of the previous year. The tax on the Group’s profit (loss) before tax differs from the theoretical • Transfers of participations in foreign entities that represent indirect disposals amount that would arise using the weighted average tax rate applicable to of assets in Colombia became subject to income tax or to the occasional profits of the consolidated entities as follows: earnings tax, depending on certain circumstances. • VAT paid for acquisition of productive fixed assets could be credited against corporate income tax. Amounts in US$ ‘000 • An audit benefit was granted by the reform, establishing that tax returns of Profit (loss) before tax 2018 208,907 2017 25,308 2016 (48,842) FY 2019 and 2020 showing a net income tax 30% or 20% higher, respectively, Tax losses from non-taxable than the one declared in the previous year would be considered definitive 6 jurisdictions months or 12 months after became due, also respectively, if there were no Taxable profit (loss) 42,808 251,715 22,708 48,016 12,318 (36,524) objections or requests from the tax authority. Argentina Income tax calculated at domestic tax rates applicable to Profit (Losses) A tax reform has been enacted in Argentina during December 2017. The in the respective countries (102,211) (31,107) (809) legislation included significant changes to certain corporate income tax and Tax losses where no deferred statutory income tax provisions, including rate reductions. Most of the tax tax benefit is recognized provisions are effective from fiscal year 2018. Effect of currency translation on tax base Changes in the income tax rate With this tax reform, the corporate income tax -previously 35%- will have the (Note 16) following rate schedule:  • 30% in 2018 and 2019 • 25% in 2020 and 2021 and onwards. Previously unrecognized tax losses Non-taxable results (a) Income tax (7,344) 3,336 (1,874) 4,882 (3,029) (8,111) (2,330) (6,616) (2,840) 542 - 220 - (2,139) (1,759) (106,240) (43,145) (11,804) Other changes include the following: • New withholding tax on dividends—with the applicable rates for non-resident shareholders of: (1) 7% for dividends distributed out of the (a) Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities. distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and Under current Bermuda law, the Company is not required to pay any taxes (2) 13% for dividends distributed out of the distributing entity’s previously in Bermuda on income or capital gains. The Company has received an taxed profits of fiscal years 2020 and onwards. undertaking from the Minister of Finance in Bermuda that, in the event of • Application of inflation adjustment for corporate tax purposes is reinstated any taxes being imposed, they will be exempt from taxation in Bermuda until under certain circumstances. March 2035. Income tax rates in those countries where the Group operates • Possible tax revaluation of investment in fixed assets, under payment of a (Colombia, Chile, Brazil, Argentina and Peru) ranges from 15% to 37%. special tax. • Allow for short term recovery of VAT paid on acquisitions or imports of The Group has significant tax losses available which can be utilised against capital goods, when non recoverable with VAT on usual sales. future taxable profit in the following countries: Amounts in US$ ‘000 Chile (a) Brazil (a) Argentina (b) Total tax losses at 31 December 2018 2017 2016 315,733 345,104 280,290 38,011 5,490 33,721 4,849 16,057 2,908 359,234 383,674 299,255 (a) Taxable losses have no expiration date. GeoPark 179 Expiring date 2021 2022 (b) Expiring dates for tax losses accumulated at 31 December 2018 are: Note 18 Amounts in US$ ‘000 The gross movement on the deferred income tax account is as follows: Deferred income tax 372 5,118 Amounts in US$ ‘000 Deferred tax at 1 January 2018 25,350 (3,574) (4,784) 2017 20,283 (237) 5,304 At the balance sheet date deferred tax assets in respect of tax losses in certain Currency translation differences companies in Chile have not been recognized as there is insufficient evidence Income statement (charge) credit of future taxable profits to offset them. Deferred tax at 31 December 16,992 25,350 The breakdown and movement of deferred tax assets and liabilities as of 31 December 2018 and 2017 are as follows: Amounts in US$ ‘000 Deferred tax assets Difference in depreciation rates and other Taxable losses Total 2018 Total 2017 Amounts in US$ ‘000 Deferred tax liabilities Difference in depreciation rates and other Taxable losses Total 2018 Total 2017 Note 19 Earnings per share At the beginning (Charged) / Currency translation Reclassification At the end of year of year credited to net profit differences 16,171 11,465 27,636 23,053 (16,383) 4,869 (11,514) 4,820 (1,897) (1,677) (3,574) (237) (968) 20,213 19,245 - (3,077) 34,870 31,793 27,636 At the beginning (Charged) / Reclassification At the end of year of year credited to net profit (20,074) 17,788 (2,286) (2,770) 4,305 2,425 6,730 484 968 (20,213) (19,245) - (14,801) - (14,801) (2,286) Amounts in US$ ‘000 except for shares Numerator Profit (Loss) for the year attributable to owners Denominator: Weighted average number of shares used in basic EPS Earnings (Losses) after tax per share (US$) – basic Amounts in US$ ‘000 except for shares Weighted average number of shares used in basic EPS Effect of dilutive potential common shares (a) Stock awards at US$ 0.001 Weighted average number of common shares for the purposes of diluted earnings per shares Earnings (Losses) after tax per share (US$) – diluted 2018 72,415 2017 2016 (24,228) (49,092) 60,612,230 60,093,191 59,777,145 1.19 (0.40) (0.82) 2018 60,612,230 2017 (a) 60,093,191 2016 (a) 59,777,145 4,758,552 - - 65,370,782 60,093,191 59,777,145 1.11 (0.40) (0.82) (a) For the year ended 31 December 2017, there were 4,564,777 (1,390,706 in 2016) of potential shares that could have a dilutive impact. They were considered antidilutive due to negative earnings. 180 GeoPark 20F Note 20 Property, plant and equipment Amounts in US$ ‘000 Cost at 1 January 2016 Additions Currency translation differences Disposals Write-off / Impairment reversal Transfers Cost at 31 December 2016 Additions Currency translation differences Disposals Write-off Transfers Cost at 31 December 2017 Additions Acquisitions (Note 35.3) Currency translation differences Disposals Write-off / Impairment reversal Transfers Assets held for sale (Note 35.2) Cost at 31 December 2018 Oil & gas Furniture, Production Buildings and Construction Exploration Total properties equipment facilities and improvements in progress 648,992 (3,531) (a) 16,132 - 5,664 24,984 692,241 7,997 (a) (1,142) - - 77,408 776,504 (5,753) (a) 52,925 (11,525) - 5,109 63,794 (163,544) 717,510 and vehicles machinery 13,745 124,832 10,518 406 126 (22) - 102 466 2,077 - - 5,038 - 35 - - - 14,357 132,413 10,553 954 (12) (112) - 211 15,398 1,706 254 (130) (46) - 566 - 17,748 (7,317) (2,702) 8 (38) - (147) - - 25,130 157,396 - 1,616 (884) (417) (120) 14,503 - 172,094 (60,614) (10,788) - (296) (71,698) (14,558) - 24 - (3) (189) - - 10,361 - 134 (30) - - - 11,554 (3,195) (920) - (16) (4,131) (844) 38 5 (4,932) (996) - 26 - 1,089 (59,332) and evaluation assets(b) 87,000 18,181 790 - (31,366) (c) (12,832) 61,773 49,455 (104) - (5,834) (d) (40,922) 914,910 35,844 19,233 (22) (25,702) - 944,263 125,359 (1,470) (301) (5,834) - 64,368 1,062,017 43,515 - (882) - (26,389) (e) (20,620) 121,429 54,929 (13,466) (463) (21,407) - 29,823 20,322 73 - - (17,292) 32,926 66,953 (62) - - (61,827) 37,990 81,961 - (15) - (7) - - (163,544) 60,597 59,992 1,039,495 - - - - - - - - - - - - - - - - - - - - - - - - - - - - (392,299) (75,490) 8 (2,836) (470,617) (75,075) 111 967 (544,614) (92,663) 191 6,747 148,014 (482,325) 473,646 517,403 557,170 Depreciation and write-down at 1 January 2016 (321,173) Depreciation Disposals Currency translation differences (61,080) - (2,486) Depreciation and write-down at 31 December 2016 (384,739) (10,049) Depreciation Disposals Currency translation differences (57,725) (1,948) - 930 73 8 Depreciation and write-down at 31 December 2017 (441,534) Depreciation Disposals Currency translation differences Assets held for sale (Note 35.2) (72,130) - 6,292 148,014 (11,916) (1,579) (86,232) (17,958) 42 92 - 149 337 - Depreciation and write-down at 31 December 2018 (359,358) (13,361) (103,704) (5,902) Carrying amount at 31 December 2016 Carrying amount at 31 December 2017 Carrying amount at 31 December 2018 307,502 334,970 358,152 4,308 3,482 4,387 60,715 71,164 68,390 6,422 5,429 5,652 32,926 37,990 60,597 61,773 64,368 59,992 (a) Corresponds to the effect of change in estimate of assets retirement obligations. (b) Exploration wells movement and balances are shown in the table below; seismic and other exploratory assets amount to US$ 48,779,000 (US$ 53,764,000 in 2017 and US$ 53,523,000 in 2016). GeoPark 181 Amounts in US$ ‘000 Exploration wells at 31 December 2016 Additions Write-offs Transfers Exploration wells at 31 December 2017 Additions Write-offs Transfers Exploration wells at 31 December 2018 Total 8,250 35,299 (3,664) (29,281) 10,604 43,103 (23,733) (18,761) 11,213 As of 31 December 2018, there were nine exploratory wells that have been capitalized for a period less than a year amounting to US$ 10,069,000 and three exploratory wells that have been capitalized for a period over a year amounting to US$ 1,144,000. (c) Corresponds to the write-off of five wells drilled in previous years in the Chilean blocks for which no additional work would be performed, the loss generated by the write-off of the seismic cost for Llanos 62 Block in Colombia generated by the relinquishment of the area in September 2016. In addition, during September 2016, five blocks in Brazil were relinquished so the associated investment was written off. (d) Corresponds to five unsuccessful exploratory wells, one well drilled in Colombia (Llanos 34 Block), one well drilled in Brazil (REC-T-94 Block) and three non-operated wells drilled in Argentina (Puelen and Sierra del Nevado Blocks) in 2017. The charge also includes the loss generated by the write-off of the seismic cost for Campanario and Isla Norte Blocks in Chile generated by the relinquishment of 327 sq km in 2017. (e) Corresponds to nine unsuccessful exploratory wells, four wells drilled in Colombia (Tiple, Llanos 34 and Llanos 32 Blocks), two wells drilled in Brazil (POT-T-747 and POT-T-619 Blocks) and three wells drilled in Argentina (Puelen Block). The change also includes the write-off of a well and other exploration costs incurred in the Fell Block (Chile) in previous years and other exploration costs incurred in the VIM-3 Block (Colombia), and POT-T-882 and REC-T-93 Blocks (Brazil), for which no additional work would be performed. 182 GeoPark 20F Note 21 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of 31 December 2018: GeoPark Limited (Bermuda) 100% 100% GeoPark Latin America Limited (Bermuda) GeoPark Argentina Limited (Bermuda) 100% 100% GeoPark Latin America Limited Agencia en Chile GeoPark Argentina Limited - Argentinean Branch 100% GeoPark (UK) Limited 100% 100% 100% GeoPark Latin America S.L.U. (Spain) GeoPark Brazil S.L.U. (Spain) GeoPark Perú S.L.U. (Spain) 91% GeoPark Chile S.A. (Chile) 9% 100% 100% 99.9% 99.9% GeoPark Colombia Coöperatie U.A. (The Netherlands) GeoPark Colombia E&P S.A. (Panama) GeoPark Brazil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) GeoPark S.A.C. (Perú) 100% 100% 99% 100% 100% GeoPark TdF S.A. (Chile) GeoPark Fell SpA. (Chile) GeoPark Magallanes Limitada (Chile) GeoPark Colombia SAS (Colombia) GeoPark Colombia E&P S.A. Sucursal Colombia 99.9% 99.9% GeoPark Perú S.A.C. (Perú) GeoPark Operadora del Perú S.A.C. (Perú) Non-controlling interest that used to be held by LG International until 28 November 2018: • Consolidated Statement of Comprehensive Income: Total comprehensive income for the year 2018 includes a profit of US$ 35,284,000 (US$ 13,536,000 in 2017 and US$ 2,791,000 in 2016), a loss of US$ 4,273,000 (US$ 6,200,000 in 2017 and US$ 10,379,000 in 2016) and a loss of US$ 758,000 (US$ 945,000 in 2017 and US$ 3,966,000 in 2016) corresponding to non-controlling interest that used to be held by LGI in GeoPark Colombia Coöperatie U.A., GeoPark Chile S.A. and GeoPark TdF S.A., respectively. • Consolidated Statement of Financial Position: Total Equity as of 31 December 2017 included US$ 29,330,000, US$ 15,953,000 and a negative amount of US$ 3,368,000 corresponding to non-controlling interest that used to be held by LGI in GeoPark Colombia Coöperatie U.A., GeoPark Chile S.A. and GeoPark TdF S.A., respectively. • Consolidated Statement of Changes in Equity: Dividends distributed to non-controlling interest of US$ 8,089,000 in 2018 (US$ 479,000 in 2017 and US$ 6,406,000 in 2016) correspond to non-controlling interest that used to be held by LGI in GeoPark Colombia Coöperatie U.A. GeoPark 183 Details of the subsidiaries and joint operations of the Group are set out below: Subsidiaries GeoPark Argentina Limited (Bermuda) Name and registered office GeoPark Argentina Limited – Argentinean Branch (Argentina) GeoPark Latin America Limited (Bermuda) GeoPark Latin America Limited – Agencia en Chile (Chile) GeoPark S.A. (Chile) GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. (Brazil) GeoPark Chile S.A. (Chile) GeoPark Fell S.p.A. (Chile) GeoPark Magallanes Limitada (Chile) GeoPark TdF S.A. (Chile) GeoPark Colombia S.A. (Chile) GeoPark Colombia S.A.S. (Colombia) GeoPark Latin America S.L.U. (Spain) GeoPark Colombia Coöperatie U.A. (The Netherlands) GeoPark S.A.C. (Peru) GeoPark Perú S.A.C. (Peru) GeoPark Operadora del Perú S.A.C. (Peru) GeoPark Peru S.L.U. (Spain) GeoPark Brasil S.L.U. (Spain) GeoPark Colombia E&P S.A. (Panama) GeoPark Colombia E&P Sucursal Colombia (Colombia) GeoPark Mexico S.A.P.I. de C.V. (Mexico) Ogarrio E&P S.A.P.I. de C.V. (Mexico) GeoPark (UK) Limited (United Kingdom) Joint operations Tranquilo Block (Chile) Flamenco Block (Chile) Campanario Block (Chile) Isla Norte Block (Chile) Llanos 34 Block (Colombia) Llanos 32 Block (Colombia) Puelen Block (Argentina) Sierra del Nevado Block (Argentina) CN-V Block (Argentina) Manati Field (Brazil) POT-T-747 Block (Brazil) REC-T-128 Block (Brazil) (a) Indirectly owned. (b) Dormant companies. (c) GeoPark is the operator. Corporate structure reorganization Ownership interest 100% 100% (a) 100% 100% (a) 100% (a) (b) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) (b) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) (b) 100% (a) (b) 100% 50% (c) 50% (c) 50% (c) 60% (c) 45% (c) 12.5% 18% 18% 50% 10% 70% (c) 70% (c) During 2017, the Company decided to incorporate a subsidiary in the United Kingdom (international investor centre) to actively conduct the strategic business and financial decisions of the Group. Also, to enhance protection to the Group’s investments in Latin America and because of a predicted change of the Dutch dividend withholding tax act that would unjustifiably affect the Group’s operating cash flow, GeoPark decided to re-domiciliate the Group´s sub-holdings from the Netherlands to Spain (jurisdiction with a broad network of Investment Promotion and Protection Agreements with Latin American countries). 184 GeoPark 20F Note 22 Prepaid taxes Amounts in US$ ‘000 V.A.T. Income tax payments in advance Other prepaid taxes Total prepaid taxes Classified as follows: Current Non-current Total prepaid taxes Note 23 Inventories Amounts in US$ ‘000 Crude oil Materials and spares Note 24 Trade receivables and Prepayments and other receivables Amounts in US$ ‘000 Trade receivables To be recovered from co-venturers (Note 33) Related parties receivables (Note 33) Prepayments and other receivables 2018 16,215 16,215 1,819 - 7,889 9,708 Amounts in US$ ‘000 At 1 January Foreign exchange income 2017 2018 594 (48) 546 2017 741 (147) 594 27,674 The credit period for trade receivables is 30 days. The maximum exposure to 1,258 credit risk at the reporting date is the carrying value of each class of receivable. 939 The Group does not hold any collateral as security related to trade receivables. 2018 37,811 9,668 966 48,445 29,871 The carrying value of trade receivables is considered to represent a reasonable 26,048 approximation of its fair value due to their short-term nature. 45,170 3,275 48,445 3,823 29,871 Note 25 Financial instruments by category Amounts in US$ ‘000 2018 3,369 5,940 9,309 2017 1,969 3,769 5,738 Financial assets at fair value through profit or loss Derivative financial instrument assets Cash and cash equivalents Other financial assets at amortized cost Trade receivables To be recovered from co-venturers (Note 33) Other financial assets (a) Cash and cash equivalents 2017 19,519 Total financial assets Assets as per statement of financial position 2018  2017 27,539 53,794 81,333 16,215 1,819 11,468 73,933 - 44,123 44,123 19,519 2,455 43,488 90,632 103,435 184,768 156,094 200,217 19,519 2,455 56 (a) Non-current other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government 5,242 regulations. Current other financial assets corresponds to short-term 7,753 investments with original maturities up to twelve months and over three Total 25,923 27,272 months. At 31 December 2017, Current other financial assets also included the security deposit granted in relation to the purchase of Argentinian assets Classified as follows: Current Non-current Total 25,704 219 25,923 (Note 35.3). 27,037 235 Amounts in US$ ‘000 27,272 Liabilities at fair value through profit and loss Trade receivables that are aged by less than three months are not considered Derivative financial instrument liabilities impaired. As of 31 December 2018 and 2017, there are no balances that were aged by more than 3 months, but not impaired. These relate to customers for Other financial liabilities at amortized cost whom there is no recent history of default. There are no balances overdue Trade payables between 31 days and 90 days as of 31 December 2018 and 2017. Payables to related parties (Note 33) Movements on the Group provision for impairment are as follows: To be paid to co-venturers (Note 33) Payables to LGI (Note 35.1) Borrowings Total financial liabilities Liabilities as per statement of financial position 2018 2017 - - 19,289 19,289 69,142 - 29,509 8,449 447,002 554,102 554,102 52,557 31,184 - 10,015 426,204 519,960 539,249 GeoPark 185 25.1 Credit quality of financial assets the contractual maturity date. The amounts disclosed in the table are the The credit quality of financial assets that are neither past due nor impaired can contractual undiscounted cash flows. be assessed by reference to external credit ratings (if available) or to historical information about counterparty default rates: Amounts in US$ ‘000 Less than Between 1 Between 2 1 year and 2 years and 5 years Over 5 years Amounts in US$ ‘000 Trade receivables Counterparties with an external credit rating (Moody’s) B2 Ba2 Ba3 Baa3 Counterparties without an external credit rating Group1 (a) Total trade receivables 2018 2017 At 31 December 2018 Borrowings Trade payables Payables to LGI (Note 35.1) At 31 December 2017 Borrowings Trade payables 70 - 8,788 3,614 7,047 Payables to related parties 19,519 39,545 68,862 15,000 123,407 27,625 52,557 7,331 87,513 38,648 280 15,000 53,928 82,875 452,625 - - - - 82,875 452,625 27,625 82,875 480,250 - - 2,068 27,087 - - 29,693 109,962 480,250 1,196 5,511 3,734 - 5,774 16,215 (a) Group 1 – existing customers (more than 6 months) with no defaults in the past. All trade receivables are denominated in US Dollars, except in Brazil where are denominated in Brazilian Real. 25.3 Fair value measurement of financial instruments Accounting policies for financial instruments have been applied to classify as either: loans and receivables, held-to-maturity, available-for-sale, or fair value through profit and loss. For financial instruments that are measured in the statement of financial position at fair value, IFRS 13 requires a disclosure Cash at bank and other financial assets (a) Amounts in US$ ‘000 2018 2017 of fair value measurements by level according to the following fair value Counterparties with an external credit rating (Moody’s, measurement hierarchy: S&P, Fitch, BRC Investor Services) A1 A2 A3 Aaa Aaa-mf Aa1 Aa3 AAA B2 Ba1 Ba2 Baa1 Baa1+ Baa2 Ba3 B3 BBB Counterparties without an external credit rating 1,315 595 765 - 52,563 4,732 17,431 14,307 - 4,033 1 13,903 4,138 6,534 212 - 3,199 15,448 • Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities. • Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices). • Level 3 - Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs). This note provides an update on the judgements and estimates made by the Group in determining the fair values of the financial instruments since the last annual financial report. 553 298 63,853 15,040 - - 11,401 19,634 31 18 7 307 - 25.3.1 Fair value hierarchy 4,078 2,815 The following table presents the Group’s financial assets and financial liabilities measured and recognized at fair value at 31 December 2018 and 2017 on a - recurring basis: 15,064 45,123 Amounts in US$ ‘000 Total 139,176 178,222 (a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 19,000 (US$ 21,000 in 2017). Assets Cash and cash equivalents Money market funds 25.2 Financial liabilities - contractual undiscounted cash flows Derivative financial instrument liabilities The table below analyses the Group’s financial liabilities into relevant Commodity risk management contracts maturity groupings based on the remaining period at the balance sheet to Total Liabilities 186 GeoPark 20F Level 1 Level 2 December At 31 2018 53,794 - 53,794 - 53,794 27,539 27,539 27,539 81,333 Amounts in US$ ‘000 Level 1 Level 2 At 31 Note 26 December Share capital 2017 Assets Cash and cash equivalents Money market funds Total Assets Liabilities Derivative financial instrument liabilities Commodity risk management contracts Total Liabilities Issued share capital Common stock (amounts in US$ ‘000) 2018 60 2017 61 44,123 44,123 - - 44,123 The share capital is distributed as follows: 44,123 Common shares, of nominal US$ 0.001 Total common shares in issue 60,483,447 60,483,447 60,596,219 60,596,219 - - 19,289 19,289 19,289 Authorized share capital 19,289 US$ per share 0.001 0.001 There were no transfers between Level 2 and 3 during the period. Number of common shares The Group did not measure any financial assets or financial liabilities at fair Amount in US$ value on a non-recurring basis as at 31 December 2018. (US$ 0.001 each) 5,171,949,000 5,171,949,000 5,171,949 5,171,949 Details regarding the share capital of the Company are set out below: 25.3.2 Valuation techniques used to determine fair values Specific valuation techniques used to value financial instruments include: Common shares • The use of quoted market prices or dealer quotes for similar instruments. following rights on the holder: • The mark-to-market fair value of the Group’s outstanding derivative • the right to one vote per share; instruments is based on independently provided market rates and • ranking pari passu, the right to any dividend declared and payable on As of 31 December 2018, the outstanding common shares confer the determined using standard valuation techniques, including the impact of common shares; counterparty credit risk and are within level 2 of the fair value hierarchy. • The fair value of the remaining financial instruments is determined using discounted cash flow analysis. All of the resulting fair value estimates are GeoPark common included in level 2. shares history Shares outstanding Shares issued Shares closing US$(`000) Date (millions) (millions) Closing 25.3.3 Fair values of other financial instruments (unrecognised) at the end of 2016 The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the majority of these instruments, the fair values are not materially different to their carrying Stock awards Stock awards Stock awards Jan 2017 Dec 2017 Dec 2017 0.1 0.1 0.5 amounts, since the interest receivable/payable is either close to current Shares outstanding market rates or the instruments are short-term in nature. at the end of 2017 Stock awards Borrowings are comprised primarily of fixed rate debt and variable rate debt Buyback program with a short-term portion where interest has already been fixed. They are Shares outstanding classified under other financial liabilities and measured at their amortized at the end of 2018 Dec 2018 Dec 2018 0.1 (0.2) 59.9 60.0 60.1 60.6 60.6 60.7 60.5 60.5 60 60 60 61 61 61 60 60 cost. The fair value of these financial instruments at 31 December 2018 amounts to Stock Award Program and Other Share Based Payments US$ 445,582,000 (US$ 425,118,000 in 2017). The fair values are based on cash Non-Executive Directors Fees flows discounted using a rate based on the borrowing rate of 6.94% (6.90% in During 2018, the Company issued 33,145 (70,485 in 2017 and 137,897 in 2017) and are within level 2 of the fair value hierarchy. 2016) shares to Non-Executive Directors in accordance with contracts as compensation, generating a share premium of US$ 449,000 (US$ 257,000 in 2017 and US$ 541,848 in 2016). The amount of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period. GeoPark 187 Stock Award Program and Other Share Based Payments The Notes carry a coupon of 6.50% per annum. Final maturity of the Notes will be 21 September 2024. The Notes are secured with a guarantee granted by On 14 December 2017, 490,000 (379,500 in 2016) common shares were GeoPark Colombia Coöperatie U.A. and GeoPark Chile S.A.. The debt issuance allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a cost for this transaction amounted to US$ 6,683,000 (debt issuance effective share premium of US$ 2,513,000 (US$ 3,940,000 in 2016). rate: 6.90%). The indenture governing the Notes due 2024 includes incurrence On 13 September 2017, 12,546 (8,333 in 2016) shares were issued pursuant years from the issuance date, the Net Debt to Adjusted EBITDA ratio should to a consulting agreement for services rendered to GeoPark Limited not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed generating a share premium of US$ 43,000 (US$ 38,000 in 2016). 2 times. Failure to comply with the incurrence test covenants does not trigger In January 2017, 82,306 shares were issued to key management as bonus to incur additional indebtedness, as specified in the indenture governing the compensation, generating a share premium of US$ 332,000. Notes. Incurrence covenants as opposed to maintenance covenants must an event of default. However, this situation may limit the Company’s capacity test covenants that provides among other things, that, during the first two On 8 February 2016, 468,405 shares were issued to Executive Directors and certain corporate actions including but not limited to dividend payments, key management as bonus compensation, generating a share premium of restricted payments and others. As of the date of these Consolidated Financial be tested by the Company before incurring additional debt or performing US$ 1,512,000. Buyback Program Statements, the Company is in compliance of all the indenture’s provisions and covenants. On 20 December 2018, the Company approved a program to repurchase up to 10% of its shares outstanding or approximately 6,063,000 shares. The (b) During February 2016, GeoPark Fell S.p.A. executed a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 to finance the acquisition of repurchase program begun on 21 December 2018 and will expire on 31 vehicles for the Chilean operation. The interest rate applicable to this loan is December 2019. During 2018, the Company purchased 145,917 common 4.14% per annum. The interest and the principal are paid on a monthly basis, shares for a total amount of US$ 1,801,000. These transactions had no impact with the final maturity in February 2019. on the Group’s results. During 2016, the Repurchase Program began on 6 April 2016 and then was (c) During October 2018, GeoPark Brazil Exploração y Produção de Petróleo e Gás Ltda. executed a loan agreement with Banco Santander for Brazilian resumed during the year until November 2016, the Company purchased Real 77,640,000 (equivalent to US$ 20,000,000 at the moment of the loan 588,868 common shares for a total amount of US$ 1,991,000. execution) to repay an existing US$-denominated intercompany loan to Note 27 Borrowings GeoPark Latin America Limited - Agencia en Chile. The interest rate applicable to this loan is CDI plus 2.25% per annum. “CDI” (Interbank certificate of deposit) represents the average rate of all inter-bank overnight transactions in Brazil. The principal and the interest are paid semi-annually, with final maturity Amounts in US$ ‘000 2018 2017 in October 2020. Resulting from this transaction, the Brazilian subsidiary has Outstanding amounts as of 31 December 2024 Notes (a) Banco de Crédito e Inversiones (b) Banco Santander (c) 426,993 426,124 that its functional currency is the Brazilian Real (see Note 3). significantly reduced its exposure to foreign currency fluctuation, considering 3 20,006 80 - As of the date of these Consolidated Financial Statements, the Group has Classified as follows: Current Non-current 447,002 426,204 available credit lines for over US$ 80,000,000. 17,975 429,027 7,664 418,540 (a) During September 2017, the Company successfully placed US$ 425,000,000 Notes which were offered to qualified institutional buyers in accordance with Rule 144A under the United States Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the United States Securities Act. 188 GeoPark 20F Note 28 Provisions and other long-term liabilities Amounts in US$ ‘000 Asset retirement Deferred obligation 29,862 Income 3,484 At 1 January 2017 Addition to provision Exchange difference 5,943 134 Foreign currency translation (134) Amortization Unwinding of discount Unused amounts reversed Amounts used during the year At 31 December 2017 Addition to provision Recovery of abandonment costs Acquisitions Exchange difference Foreign currency translation - 2,607 - (337) 38,075 462 (4,817) 9,738 1,823 1,648 - - - (657) - - (1,375) 1,452 - - - - - Amortization - (1,005) Unwinding of discount Unused amounts reversed Amounts used during the year 3,250 - (750) Liabilities associated with assets held for sale At 31 December 2018 (5,816) 40,317 - - - - 447 Note 29 Trade and other payables Amounts in US$ ‘000 V.A.T Total 42,509 8,163 1,288 (134) (657) Trade payables Payables to related parties (Note 33) (a) Payables to LGI (Note 35.1) Customer advance payments Other short-term advance payments (b) Staff costs to be paid 2,779 Royalties to be paid (2,535) Taxes and other debts to be paid To be paid to co-venturers (Note 33) (5,129) 46,284 Classified as follows: 1,501 Current Non-current 2018 852 69,142 - 29,509 6,300 9,000 12,049 6,238 4,670 8,449 2017 1,118 52,557 31,184 - 10,000 - 9,143 4,110 4,191 10,015 146,209 122,318 131,420 14,789 96,397 25,921 (5,916) 9,738 1,777 (1,648) (1,005) 3,423 (2,093) (a) The outstanding amount at 31 December 2017 corresponded to advanced cash call payments granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s blocks and was fully cancelled on 28 November 2018 (see Note 35.1). (b) Advance payment collected in relation with the sale of La Cuerva and Yamu Blocks (see Note 35.2). Other 9,163 2,220 1,154 - - 172 (2,535) (3,417) 6,757 1,039 (1,099) - (46) - - 173 (2,093) (124) (874) The average credit period (expressed as creditor days) during the year ended (2,794) 1,813 (8,610) 31 December 2018 was 83 days (2017: 95 days). 42,577 The fair value of these short-term financial instruments is not individually The provision for asset retirement obligation relates to the estimation of future determined as the carrying amount is a reasonable approximation of fair value. disbursements related to the abandonment and decommissioning of oil and gas wells (see Note 4). Note 30 Share-based payment Deferred income relates to contributions received to improve the project The Group has established different stock awards programs and other share- economics of the gas wells in Chile. The amortization is in line with the related based payment plans to incentivize the Directors, senior management and asset. The amount used in 2017 corresponds to the deferred income related to employees, enabling them to benefit from the increased market capitalization the take-or-pay provision associated to gas sales in Brazil. of the Company. During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees, directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company and its shareholders. This Plan is designed as a master plan, with a 10-year term, and embraces all equity incentive programs that the Company decides to implement throughout such term. The maximum number of Shares available for issuance under the Plan is 5,000,000 Shares. GeoPark 189 During 2018, the Group approved a share-based compensation program Also during 2016, the Group approved a plan named Value Creation Plan for approximately 200,000 shares. Main characteristics of the Stock Awards (“VCP”) oriented to Top Management. VCP was subject to certain market Programs are: conditions, among others, reaching a stock market price for the Company • Employees hired since July 2016 are eligible. shares of US$ 4.05 at vesting date. VCP has been classified as an equity-settled • Exercise price is equal to the nominal value of shares. plan. On 2 January 2019, 50% of the shares, representing 1,488,391 shares, • Vesting date is 30 June 2019. were issued since the plan vested. The remaining 50% will be issued in January • Each employee could receive up to three salaries (to be pro-rated between 2020, as set up in the plan. the hiring date and the vesting date divided by 3 years) by achieving the following conditions: continue to be an employee, the stock market price at Details of these costs and the characteristics of the different stock awards the date of vesting should be higher than the share price at the date of grant programs and other share-based payments are described in the following and obtain the Group minimum production, adjusted EBITDA and reserves table and explanations: target for the year of vesting. During 2016, the Group approved a share-based compensation program for 1,619,105 shares. Main characteristics of the Stock Awards Programs are: • All employees are eligible. • Exercise price is equal to the nominal value of shares. • Vesting date is 30 June 2019. • Each employee could receive up to three salaries by achieving the following conditions: continue to be an employee, the stock market price at the date of vesting should be above US$ 3 and obtain the Group minimum production, adjusted EBITDA and reserves target for the year of vesting. Awards at the Awards granted Awards Awards Awards Charged to net loss / profit Year of issuance beginning in the year forfeited exercised at year end 2018 2016 2014 2012 Subtotal Shares granted to Non-Executive Directors VCP 2016 Executive Directors Bonus Key Management Bonus Stock awards for service contracts - 200,000 1,587,996 - - - - - - (5,570) - - 1,587,996 200,000 (5,570) - - - - - 200,000 1,582,426 - - 2018 1,662 886 - - 2017 2016 - 865 838 - - 445 821 855 1,782,426 2,528 1,703 2,121 - - - - - 33,145 2,976,781 104,439 - - - - - - - (33,145) - - - - - 2,976,781 104,439 - - 450 1,868 600 - - 454 1,868 - - 50 400 934 (325) 202 35 1,587,996 3,314,365 (5,570) (33,145) 4,863,646 5,446 4,075 3,367 The awards that are forfeited correspond to employees that had left the Group before vesting date. 190 GeoPark 20F GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. 31,266 30,053 17,963 Note 31 Interests in Joint operations operator in all the blocks. In Argentina, GeoPark used to be the operator in CN-V Block until October 2018. The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Chile, Colombia, Brazil and Argentina. The following amounts represent the Group’s share in the assets, liabilities In Colombia, GeoPark is the operator in Llanos 34. In Chile, GeoPark is the Consolidated Statement of Financial Position and Statement of Income: and results of the joint operations which have been recognized in the Interest PP&E Other Assets Total Total Net Assets/ Operating Assets Liabilities (Liabilities) Revenue profit (loss) 45% 12.5% 174,895 2,011 3,133 178,028 175,732 469,404 347,772 2,011 1,562 5,764 (2,296) (449) Subsidiary / Joint operation 2018 Colombia SAS Llanos 34 Block Llanos 32 Block GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block 50% 50% 50% 60% 10% 70% 70% 50% 18% 18% 45% 12.5% 89.5% 50% 50% 50% 60% Manati Field POT-T-747 REC-T-128 GeoPark Argentina Limited – Argentinean Branch CN-V Block Puelen Block Sierra del Nevado Block GeoPark Perú S.A.C. Morona 2017 Colombia SAS Llanos 34 Block Llanos 32 Block Yamu/Carupana Block GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field POT-T-747 GeoPark Argentina Limited – Argentinean Branch CN-V Block Puelen Block Sierra del Nevado Block 10% 70% 50% 18% 18% - 55 - - - 6,364 - - 328 13 10 - 4,803 16,477 8,920 25,741 202 1,398 8,577 1,881 995 835 4,741 - 9,893 17,347 9,553 44,167 849 6,819 1,138 568 209 1 55 - - - 19,126 358 347 72 169 55 (428) (373) 4,803 16,477 8,920 32,105 202 1,398 8,905 1,894 1,005 (1,173) (278) (72) 3,630 16,199 8,848 (839) - (648) (577) (246) (91) 202 750 8,328 1,648 914 623 (46) (5,647) (1,008) (778) - 263 40 7 - - - - - - - - (922) (159) (134) - 55 (432) (377) - (48) 9,893 17,347 9,553 63,293 1,207 7,166 1,390 737 (1,223) (233) (60) (11,444) (1,091) (984) (232) (837) 8,670 17,114 9,493 51,849 116 6,182 1,158 (100) 879 (1,422) - - (150) (161) 34,238 12,731 - 70 - - - (1,163) (546) (474) GeoPark 191 75% 6,446 - 6,446 (7,016) (570) 131,193 4,563 135,756 1,044 4,742 (5,847) (492) (2,993) 129,909 259,815 163,917 552 1,749 1,784 3,072 (319) (2,721) Subsidiary / Joint operation 2016 Colombia SAS Llanos 34 Block Llanos 32 Block Yamu/Carupana Block GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Interest PP&E Other Assets Total Total Net Assets/ Operating Assets Liabilities (Liabilities) Revenue profit (loss) 45% 10% 89.5% 50% 50% 50% 60% 79,811 3,819 3,418 - 15,108 29,718 9,920 693 - - 55 - - - 80,504 3,819 3,418 (3,943) (211) (2,289) 76,561 125,400 3,608 1,129 2,303 18 83,193 1,043 (307) 55 (424) (369) - (40) 15,108 29,718 9,920 (93) (1) (1) 15,015 29,717 9,919 1,004 (1,988) - 5 (399) (438) GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10% 54,166 15,791 69,957 (8,442) 61,515 29,719 20,945 Capital commitments are disclosed in Note 32.2. Note 32 Commitments 32.1 Royalty commitments In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using a level of production sliding scale at a rate which ranges between 6%-8%. The Colombian National Hydrocarbons Agency (“ANH”) also has an additional economic right equivalent to 1% of production, net of royalties. Q = Economic right to be delivered to ANH, P = WTI, Po = Base price (see table A) and S = Share (see table B). °API >29° >22°<29° >15°<22° >10°<15° Po (US$/barrel) 30.22 31.39 32.56 46.50 Table A Table B WTI (P) Po < P < 2Po 2Po < P < 3Po 3Po < P < 4Po 4Po < P < 5Po 5Po < P S 30% 35% 40% 45% 50% Additionally, under the terms of the Winchester Stock Purchase Agreement, Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties on GeoPark is obligated to make certain payments to the previous owners of Colombian production of light and medium oil are calculated on a field-by- Winchester based on the production and sale of hydrocarbons discovered field basis, using the following sliding scale: by exploration wells drilled after 25 October 2011. These payments involve Average daily production in barrels Production Royalty rate the vendor. As at the balance sheet date and based on preliminary internal Up to 5,000 5,000 to 125,000 125,000 to 400,000 400,000 to 600,000 Greater than 600,000 8% estimates of additions of 2P reserves since acquisition, the Group’s best 8% + (production - 5,000) * 0.1 estimate of the total commitment over the remaining life of the concession is 20% in a range between US$ 150,000,000 and US$ 160,000,000. During 2018, the 20% + (production - 400,000) * 0.025 Group has accrued US$ 20,551,000 (US$ 11,369,000 in 2017 and US$ 5,414,000 25% in 2016) and paid US$ 19,128,000 (US$ 9,981,000 in 2017 and US$ 3,772,000 in an overriding royalty equal to an estimated 4% carried interest on the part of When the API is lower than 15°, the payment is reduced to the 75% of the total calculation. 2016). In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties are calculated at 5% of crude oil production and 3% of gas In accordance with Llanos 34 Block operation contract, when the production. In the Flamenco Block, Campanario Block and Isla Norte Block, accumulated production of each field, including the royalties’ volume, royalties are calculated at 5% of gas and oil production. exceeds 5,000,000 of barrels and the WTI exceeds the base price settled in table A, the Group should deliver to ANH a share of the production net of In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency royalties in accordance with the following formula: Q = ((P – Po) / P) x S; where (ANP) is responsible for determining monthly minimum prices for petroleum 192 GeoPark 20F produced in concessions for purposes of royalties payable with respect Campanario and Isla Norte Blocks as well as the guarantees related to those to production. Royalties generally correspond to a percentage ranging commitments. Consequently, the future investment commitments assumed between 5% and 10% applied to reference prices for oil or natural gas, by GeoPark for the second exploratory period are up to: as established in the relevant bidding guidelines (edital de licitação) and • Campanario Block: 3 exploratory wells before 10 July 2019 (US$ concession agreement. In determining the percentage of royalties applicable 4,758,000) to a concession, the ANP takes into consideration, among other factors, the • Isla Norte Block: 2 exploratory wells before 7 May 2019 (US$ 2,855,000) geological risks involved and the production levels expected. In the Manati Block, royalties are calculated at 7.5% of gas production. As of 31 December 2018, the Group has established guarantees for its total In Argentina, crude oil and gas production accrues royalties payable to the commitments. Provinces of Mendoza and Neuquen equivalent to 15% on estimated value On 20 December 2018, GeoPark proposed to extend the second exploratory at well head of those products. This value is equivalent to final sales price less period for an additional period of 18 months, ending 11 January 2021 and 7 transport, storage and treatment costs. November 2020, respectively. As of the date of these consolidated financial 32.2 Capital commitments statements the Chilean Ministry has not replied. 32.2.4 Brazil 32.2.1 Colombia The future investment commitments assumed by GeoPark are up to: The VIM 3 Block minimum investment program consists of 200 km of 2D • REC-T-94 Block: 1 exploratory well before 7 February 2020 (US$ 930,000). seismic and drilling one exploratory well, with a total estimated investment • REC-T-128 Block: 1 exploratory well before 20 December 2018 (US$ of US$ 22,290,800 during the initial three-year exploratory period ending 2,200,000). As of the date of these Consolidated Financial Statements, GeoPark 2 September 2018. On 12 September 2018, the Colombian National has already drilled the committed well, with testing expected for the first Hydrocarbons Agency (“ANH”) accepted GeoPark’s proposal to extend the first quarter of 2019. exploratory phase for an additional period ending 12 May 2019. Additionally, • POT-T-747 Block: 1 exploratory well before 20 December 2018 (US$ 490,000). GeoPark requested ANH to terminate the E&P Contract due to environmental On 15 January 2019, the Brazilian National Agency of Petroleum, Natural Gas restrictions in the block. These restrictions became apparent once the National and Biofuels (“ANP”) notified the suspension of the exploratory period to fulfil Authority of Environmental Licenses (ANLA) issued the environmental the commitments in the block. license. As of the date of these consolidated financial statements, GeoPark’s • POT-T-785 Block: 3D seismic and electromagnetic survey before 29 January termination request is under review. 2023 (US$ 90,000). The Llanos 34 Block (45% working interest) has committed to drill an 32.2.5 Argentina exploratory well, which amounts to US$ 1,935,000 at GeoPark’s working The remaining commitment in the Sierra del Nevado Block (18% working interest, before 19 September 2019. 32.2.2 Chile interest) for the first exploratory period, ending on 20 August 2019, amounts to between US$ 500,000 and US$ 1,000,000 at GeoPark’s working interest The remaining investment commitment for the second exploratory phase The investment commitment in the CN-V Block (50% working interest) for the in the Flamenco Block relates to the drilling of one exploratory well to be current exploratory period denominated as “Field under evaluation”, ending assumed 100% by GeoPark and amounts to US$ 2,100,000. On 30 June 2017, on 27 November 2021, amounts to US$ 1,300,000 at GeoPark’s working the Chilean Ministry accepted GeoPark’s proposal to extend the second interest. exploratory phase for an additional period of 18 months, ending on 7 May 2019. On 20 December 2018, GeoPark proposed to extend the second The investment commitment in the Los Parlamentos Block (50% working exploratory period for an additional period of 18 months, ending 7 November interest) for the first exploratory period, ending on 30 October 2021, which 2020. As of the date of these consolidated financial statements the Chilean includes 2 exploratory wells and additional 3D seismic, amounts to US$ Ministry has not replied. 6,000,000, at GeoPark’s working interest. The investment commitment for the first exploratory period in the 32.3 Operating lease commitments – Group company as lessee Campanario and Isla Norte Blocks has already been fulfilled. The investments to be made in the second exploratory period will be assumed The Group leases various plant and machinery under non-cancellable 100% by GeoPark. On 29 May 2017, the Chilean Ministry accepted operating lease agreements. The Group also leases offices under non- GeoPark’s proposal to update the value of the commitments in both the cancellable operating lease agreements. The lease terms are between 2 and GeoPark 193 3 years, and most of lease agreements are renewable at the end of the lease vehicles. The information set forth above and listed in the table is based solely period at market rate. on the disclosure set forth in Mr. O´Shaughnessy’s most recent Schedule 13G During 2018 a total amount of US$ 12,485,000 (US$ 46,195,000 in 2017 and US$ 47,871,000 in 2016) was charged to the income statement and US$ 38,229,000 of operating leases were capitalized as Property, plant and (c) The information set forth above and listed in the table is based solely on the disclosure set forth in Compass Group LLC’s most recent Schedule 13F filed equipment related to rental of drilling equipment and machinery (US$ with the SEC on 6 February 2019. 34,160,000 in 2017 and US$ 32,058,000 in 2016). filed with the SEC on 13 February 2019. The future aggregate minimum lease payments under non-cancellable operating leases are as follows: Amounts in US$ ‘000 Falling due within 1 year Falling due within 1 – 3 years Falling due within 3 – 5 years Falling due over 5 years (d) Beneficially owned by Renaissance Technologies Holdings Corporation and Renaissance Technologies LLC (jointly “Renaissance”). The in-formation set forth above and listed in the table is based solely on the disclosure set forth in Renaissance’s most recent Schedule 13G filed with the SEC on 12 February 2018 47,450 18,032 2,500 1,956 2017 32,180 5,777 2,793 - 2016 2019. 67,752 14,031 5,066 (e) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 91,312 114 common shares held by him personally. Total minimum lease payments 69,938 40,750 86,963 Note 33 Related parties Controlling interest The main shareholders of GeoPark Limited, a company registered in Bermuda, as of 31 December 2018, are: Shareholder James F. Park (a) Gerald E. O’Shaughnessy (b) Manchester Financial Group, LP Compass Group LLC (c) Renaissance Technologies Holdings Corporation (d) Juan Cristóbal Pavez (e) Other shareholders Common shares 7,891,269 6,943,316 5,246,296 3,899,301 3,527,000 2,969,116 30,007,149 60,483,447 Percentage of outstanding common shares 13.05% 11.48% 8.67% 6.45% 5.83% 4.91% 49.61% 100.00% (a) Held by Energy Holdings, LLC, which is controlled by James F. Park. The number of common shares held by Mr. Park does not reflect the 1,533,927 common shares held as of 31 December 2018 in the Company´s employee benefit trust and to which Mr. Park has voting power. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on 13 February 2019. (b) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, GPK Holdings, The Globe Resources Group, Inc., and other investment 194 GeoPark 20F Balances outstanding and transactions with related parties Account (Amounts in ´000) Transaction in the year Balances at year end Related Party Relationship 2018 To be recovered from co-venturers To be paid to co-venturers Financial results Geological and geophysical expenses Administrative expenses 2017 To be recovered from co-venturers Prepayments and other receivables Payables account To be paid to co-venturers Financial results Geological and geophysical expenses Administrative expenses 2016 To be recovered from co-venturers Prepayments and other receivables Payables account To be paid to co-venturers Financial results Geological and geophysical expenses Administrative expenses - - 1,606 170 547 - - - - 2,224 170 411 - - - - 1,587 113 371 1,819 (8,449) - - - 2,455 56 (31,184) (10,015) - - - 3,311 42 (27,801) (1,614) - - - Joint Operations Joint Operations LGI Carlos Gulisano Pedro E. Aylwin Joint Operations Joint Operations Partner Non-Executive Director (a) Executive Director (b) Joint Operations Joint Operations LGI LGI Joint Operations LGI Carlos Gulisano Pedro E. Aylwin Partner Partner Joint Operations Partner Non-Executive Director (a) Executive Director (b) Joint Operations Joint Operations LGI LGI Joint Operations LGI Carlos Gulisano Pedro E. Aylwin Partner Partner Joint Operations Partner Non-Executive Director (a) Executive Director (b) (a) Corresponding to consultancy services. (b) Corresponding to wages and salaries for US$ 417,000 (US$ 271,000 in 2017 and US$ 246,000 in 2016) and bonus for US$ 130,000 (US$ 140,000 in 2017 and Note 35 Business transactions US$ 125,000 in 2016). 35.1 General There have been no other transactions with the Board of Directors, Executive Acquisition of Non-controlling interest in Colombia and Chile’s business from officers, significant shareholders or other related parties during the year LG International besides the intercompany transactions which have been eliminated in the On 28 November 2018, GeoPark executed an agreement to acquire the LG Consolidated Financial Statements, the normal remuneration of Board of International Corporation (“LGI”) interest in GeoPark’s Colombian and Chilean Directors and other benefits informed in Note 11. operations and subsidiaries. Note 34 Fees paid to Auditors Amounts in US$ ‘000 Audit fees Audit related fees Tax services fees Non-audit services fees Fees paid to auditors The acquisition price includes a fixed payment of US$ 81,000,000 paid at closing, plus two equal installments of US$ 15,000,000 each, to be paid in 2017 2016 June 2019 and June 2020. Additionally, three contingent payments of US$ 726 137 212 39 487 5,000,000 each could be payable over the next three years, subject to certain - production thresholds being exceeded. 134 - Through this transaction, GeoPark acquired the shares that used to be held 2018 797 - 209 - 1,006 1,114 621 by LGI representing 20% equity interest in GeoPark Colombia Coöperatie U.A., 20% equity interest in GeoPark Chile S.A. and 14% equity interest in GeoPark TdF S.A. In addition to that, the outstanding amount corresponding Non-audit services fees relate to consultancy and other services for 2017. to advanced cash call payments granted in the past by LGI to GeoPark Chile GeoPark 195 S.A. for financing Chilean operations in TdF’s blocks were considered as part of 12.5% WI). The farm-in agreement provided for the drilling of an exploration the transaction. well to be funded by GeoPark and, in the event of a commercial discovery, GeoPark would increase its economic interest to 56.25% in the Zamuro field The transaction mentioned above has been accounted for as a transaction area. The well was spudded with unsuccessful results during 2018. with non-controlling interest in accordance with IFRS 10. Consequently, the difference between the amount by which the non-controlling interest was Acquisition of Tiple Block stated and the fair value of the consideration paid was recognized directly in GeoPark executed a joint operation agreement related to certain exploration Equity and attributed to the owners of the Company. activities in an exploration acreage (“Tiple Block Acreage”) in the Llanos Basin The following table summarizes the result of this transaction: of CEPSA SAU, the Spanish integrated energy and petrochemical company). in Colombia, through a partnership with CEPSA Colombia S.A. (a subsidiary The agreement provided for GeoPark to drill one exploration well, which was Amounts in US$ ‘000 Cash Additional installments to be paid Total consideration Equity attributable to non-controlling interest Trade and other payables Total book value of the transaction Total spudded with unsuccessful results during 2018. 81,000 29,427 Incremental interest in Llanos 32 Block 110,427 On 22 August 2017, GeoPark acquired an additional 2.5% interest in the Llanos 32 Block. No gain or loss has been generated by this transaction. 64,245 32,786 97,031 35.3 Argentina Result of the transaction recognized in Equity 13,396 35.2 Colombia Sale of La Cuerva and Yamu Blocks Acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks On 27 March 2018, GeoPark acquired a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks, which are located in the Neuquen Basin, for a total consideration of US$ On 2 November 2018, GeoPark executed a purchase and sale agreement to 52,000,000, less a working capital adjustment of US$ 3,150,000. The Group has sell its 100% working interest in the La Cuerva and Yamu Blocks, in Colombia. estimated that there are no any future contingent payments at the acquisition The total consideration is US$ 18,000,000, plus a contingent payment of date and as of the date of these consolidated financial statements either. US$ 2,000,000 (depending on the oil price performance) and subject to working capital adjustments. As of the date of these Consolidated Financial In accordance with the acquisition method of accounting, the acquisition Statements, GeoPark has collected an advance payment of US$ 9,000,000. cost was allocated to the underlying assets acquired and liabilities assumed Closing of the transaction is subject to customary regulatory approvals, which based primarily upon their estimated fair values at the date of acquisition. An are expected to occur during 2019. income approach (being the net present value of expected future cash flows) was adopted to determine the fair values of the mineral interest. Estimates The following table summarizes the book value of the assets and liabilities of expected future cash flows reflect estimates of projected future revenues, related to these blocks as of 31 December 2018: production costs and capital expenditures based on our business model. Amounts in US$ ‘000 Property, plant and equipment (a) Inventories Other assets (a) Provision for other long-term liabilities (b) Other liabilities (b) Total identifiable net assets (a) Classified as “Assets held for sale”. (b) Classified as “Liabilities associated with assets held for sale”. Zamuro Farm-in agreement Total The following table summarizes the combined consideration paid for the 15,530 acquired blocks and the final allocation of fair value of the assets acquired and 1,033 7,756 (8,610) (1,664) 14,045 liabilities assumed for the abovementioned transaction: Amounts in US$ ‘000 Cash (a) Total consideration Property, plant and equipment (including mineral interest) Inventories Provision for other long-term liabilities Total identifiable net assets Total 48,850 48,850 54,929 3,659 (9,738) 48,850 GeoPark executed a farm-in agreement to drill the Zamuro exploration prospect, which is located in the Llanos 32 Block (GeoPark non-operated, (a) In December 2017, GeoPark granted a security deposit of US$ 15,600,000. In March 2018, the Group completed the total consideration with an additional 196 GeoPark 20F payment of US$ 36,400,000. In September 2018, Geo-Park collected a working capital adjustment of US$ 3,150,000. In accordance with disclosure requirements for business combinations, the to carry Petroperu on a work program that provides for testing and start- Group has calculated its consolidated revenue and profit, considering as if the up production of one of the existing wells in the field, subject to certain mentioned acquisition had occurred at the beginning of the reporting period. technical and economic conditions being met. During 2017, GeoPark recognized an initial consideration owed to Petroperu of US$ 10,684,000. The following table summarizes both results: In 2018, after GeoPark’s review and approval of supporting documentation, Amounts in US$ ‘000 Revenue Profit for the period the consideration was reduced in US$ 806,000, resulting in a total amount of 2018 US$ 9,878,000. This amount will be offset by the Petroperu’s interest in the 612,401 operation expenses to be incurred by GeoPark in the block. Expected capital 102,873 expenditures in 2019 for the Morona Block are mainly related to flexible pipeline installation, temporary access road, location conditioning and The revenue included in the consolidated statement of comprehensive Morona Camp dock revamping. These activities are subject to the approval of income since acquisition date contributed by the acquired business is US$ the Environmental Impact Study, which is under review by the local authority 35,879,000. The acquired business has also contributed profit of US$ 124,000 as of the date of these consolidated financial statements. over the same period. Note 36 As a consequence of this transaction, the Group considers that there is Impairment test on Property, plant and equipment sufficient evidence of future taxable profits to offset tax losses and recognize a deferred tax asset for US$ 1,346,000 in respect of tax losses from previous As a result of the oil price crisis which started in the second half of 2014, years which can be utilised against future taxable profit. the Group recognized an impairment loss of US$ 149,574,000 in 2015 after Los Parlamentos Block evaluating the recoverability of its fixed assets affected by oil price drop, as such situation constitutes an impairment indicator according to IAS 36 and, In June 2018, GeoPark acquired a 50% working interest in the Los Parlamentos consequently, it triggers the need of assessing the fair value of the assets exploratory block in partnership with YPF S.A. (YPF), the largest oil and gas involved against their carrying amount. producer in Argentina. In accordance with the partnership agreement, YPF assumed the operationship of the block and GeoPark assumed a commitment The Management of the Group considers as Cash Generating Unit (CGU) each to fund its 50% working interest of one exploratory well and additional 3D of the blocks in which the Group has working or economic interests. The seismic, which amounts to US$ 6,000,000 at GeoPark’s working interest, over blocks with no material investment on fixed assets or with operations that are the next three years. not linked to oil prices were not subject to the impairment test. 35.4 Peru Entry in Peru During 2016, 2017 and 2018 the impairment tests were reviewed. The main assumptions taken into account for the impairment tests for the blocks below mentioned were: The Group has executed a Joint Investment Agreement and Joint Operating Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in · The future oil prices have been calculated taking into consideration the and operate the Morona Block located in northern Peru. GeoPark will assume oil price curves available in the market, provided by international advisory a 75% working interest (“WI”) of the Morona Block, with Petroperu retaining companies, weighted through internal estimations in accordance with price a 25% WI. The transaction has been approved by the Board of Directors of curves used by D&M; both Petroperu and GeoPark. The agreement was subject to Peru regulatory · Three oil price scenarios were projected and weighted in order to minimize approval, which was completed on 1 December 2016 following the issuance of misleading estimations: low-price, middle-price and high-price (see below Supreme Decree 031-2016-MEM. table “Oil price scenarios”); · The table “Oil price scenarios” was based on Brent future price estimations; The Morona Block, also known as Lote 64, covers an area of 1.9 million the Group adjusted this marker price on its model valuation to reflect the acres on the western side of the Marañón Basin, one of the most prolific effective price applicable in each location (see Note 3 “Price risk”); hydrocarbon basins in Peru. It contains the Situche Central oil field, which has · The model valuation was based on the expected cash flow approach; been delineated by two wells (with short-term tests of approximately 2,400 · The revenues were calculated linking price curves with levels of production and 5,200 bopd of 35-36° API oil each) and by 3D seismic. according to certified reserves (see below table “Oil price scenarios”); · The levels of production have been linked to certified risked 1P, 2P and 3P In accordance with the terms of the agreement, GeoPark has committed reserves (see Note 4); GeoPark 197 · Production and structure costs were estimated considering internal Note 37 historical data according to GeoPark’s own records and aligned to the 2019 Supplemental information on oil and gas activities (unaudited). approved budget; · The capital expenditures were estimated considering the drilling campaign The following information is presented in accordance with ASC No. 932 necessary to develop the certified reserves; “Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and · The assets subject to impairment test are the ones classified as Oil and Gas Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in properties and Production facilities and machinery; order to align the current estimation and disclosure requirements with the · The carrying amount subject to impairment test includes mineral interest, if requirements set in the SEC final rules and interpretations, published on 31 any; December 2008. This information includes the Group’s oil and gas production · The income tax charges have considered future changes in the applicable activities carried out in Colombia, Chile, Brazil, Argentina and Peru. income tax rates (see Note 16). Table Oil price scenarios (a): Table 1 - Costs incurred in exploration, property acquisitions and development (a) Amounts in US$ per Bbl. that were incurred during each of the years ended as of 31 December 2018, The following table presents those costs capitalized as well as expensed Low price Middle price High price Weighted market 2017 and 2016. The acquisition of properties includes the cost of acquisition (15%) (60%) (25%) price used for the of proved or unproved oil and gas properties. Exploration costs include Year 2019 2020 2021 Over 2022 63.9 51.2 53.3 55.1 63.9 68.2 71.0 73.4 63.9 75.0 78.1 80.7 impairment test geological and geophysical costs, costs necessary for retaining undeveloped 63.9 67.3 70.1 72.5 properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves. (a) The percentages indicated between brackets represent the Group estimation regarding each price scenario. As a consequence of the evaluation, the following amounts of impairment loss were reversed (recognized): Amounts in US$ ‘000 Colombia (a) Chile (b) Total 2018 11,531 (6,549) 4,982 2017 - - - 2016 5,664 - 5,664 (a) Reversal of impairment losses due to increases in estimated market prices and improvements in cost structure, and also the known fair value less costs of disposal of the La Cuerva and Yamu Blocks (see Note 35.2). (b) Recognition of impairment loss due to the termination of the sales agreement for the TdF’s blocks, with no renovation in place as of the date of these consolidated financial statements. 198 GeoPark 20F Amounts in US$ ‘000 Year ended 31 December 2018 Acquisition of properties Proved Unproved Total property acquisition Exploration Development Total costs incurred Amounts in US$ ‘000 Year ended 31 December 2017 Acquisition of properties Proved Unproved Total property acquisition Exploration Development Total costs incurred Amounts in US$ ‘000 Year ended 31 December 2016 Acquisition of properties Proved Unproved Total property acquisition Exploration Development Total costs incurred (a) Includes capitalized amounts related to asset retirement obligations. Table 2 - Capitalized costs related to oil and gas producing activities The following table presents the capitalized costs as at 31 December 2018, 2017 and 2016, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates. Amounts in US$ ‘000 At 31 December 2018 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects (b) Unproved properties Gross capitalized costs Accumulated depreciation Total net capitalized costs Colombia Chile Brazil Argentina Perú Total - - - 34,242 65,174 99,416 Colombia - - - 37,017 49,268 86,285 Colombia - - - 6,221 3,033 9,254 Chile - - - 3,283 10,231 13,514 Chile - - - 3,217 (2,220) 997 54,541 - 54,541 9,383 1,836 11,219 Brazil Argentina - - - - - - - - - 1,269 8,385 9,654 Perú - - - 54,541 - 54,541 54,332 76,208 130,540 Total - - - 5,207 1,210 6,417 Brazil 8,080 167 8,247 Argentina 743 14,074 14,817 Perú 54,330 74,950 129,280 Total - - - - - - 15,233 12,500 27,733 5,519 4,566 10,085 - - - 2,555 191 2,746 - - - 1,894 - 1,894 - - - - - - - - - 25,201 17,257 42,458 Colombia Chile Brazil Argentina Total 83,023 189,514 24,061 1,676 81,459 400,338 12,233 41,162 298,274 535,192 (122,479) (281,062) 175,795 254,130 5,154 63,574 - 7,073 75,801 (43,158) 32,643 2,458 64,084 1,836 10,081 78,459 172,094 717,510 38,130 59,992 987,726 (16,363) (463,062) 62,096 524,664 (a) Includes capitalized amounts related to asset retirement obligations, impairment loss in Chile for US$ 6,549,000 and impairment loss reversal in Colombia for US$ 11,531,000. (b) Do not include Peru capitalized costs. GeoPark 199 Amounts in US$ ‘000 At 31 December 2017 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects (b) Unproved properties Gross capitalized costs Accumulated depreciation Total net capitalized costs (a) Includes capitalized amounts related to asset retirement obligations. (b) Do not include Peru capitalized costs. Amounts in US$ ‘000 At 31 December 2016 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects Unproved properties Gross capitalized costs Accumulated depreciation Total net capitalized costs Colombia Chile Brazil Argentina Total 69,906 291,050 11,290 4,106 80,611 397,031 12,508 49,702 376,352 539,852 (228,793) (253,764) 147,559 286,088 6,036 77,264 70 7,585 90,955 (39,509) 51,446 843 11,159 48 2,975 157,396 776,504 23,916 64,368 15,025 1,022,184 (5,700) 9,325 (527,766) 494,418 Colombia Chile Brazil Argentina Total 46,785 230,100 12,534 4,503 80,611 380,037 18,274 48,908 293,922 527,830 (190,025) (230,917) 103,897 296,913 4,174 77,255 2,082 6,468 89,979 (29,803) 60,176 843 4,849 36 1,894 7,622 (5,692) 1,930 132,413 692,241 32,926 61,773 919,353 (456,437) 462,916 (a) Includes capitalized amounts related to asset retirement obligations and impairment loss reversal in Colombia for US$ 5,664,000. Table 3 - Results of operations for oil and gas producing activities The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended 31 December 2018, 2017 and 2016. Income tax for the years presented was calculated utilizing the statutory tax rates. Amounts in US$ ‘000 Year ended 31 December 2018 Revenue Production costs, excluding depreciation Operating costs Royalties Total production costs Exploration expenses (a) Accretion expense (b) Impairment loss reversal for non-financial assets Depreciation, depletion and amortization Results of operations before income tax Income tax benefit (expense) Results of oil and gas operations 200 GeoPark 20F Colombia Chile Brazil Argentina Total 497,870 37,359 30,053 35,879 601,161 (55,823) (62,710) (20,426) (1,473) (118,533) (21,899) (23,953) (892) 11,531 (6,855) (1,105) (6,549) (5,965) (2,820) (8,785) (2,846) (918) - (41,850) (27,298) (10,278) 324,173 (26,347) (119,944) 3,952 204,229 (22,395) 7,226 (2,457) 4,769 (20,210) (102,424) (4,833) (71,836) (25,043) (174,260) (2,277) (508) - (10,662) (2,611) (35,931) (3,423) 4,982 (90,088) 302,441 783 (117,666) (1,828) 184,775 Amounts in US$ ‘000 Year ended 31 December 2017 Revenue Production costs, excluding depreciation Operating costs Royalties Total production costs Exploration expenses (a) Accretion expense (b) Depreciation, depletion and amortization Results of operations before income tax Income tax benefit (expense) Results of oil and gas operations Amounts in US$ ‘000 Year ended 31 December 2016 Revenue Production costs, excluding depreciation Operating costs Royalties Total production costs Exploration expenses (a) Accretion expense (b) Impairment loss for non-financial assets Depreciation, depletion and amortization Results of operations before income tax Income tax benefit (expense) Results of oil and gas operations Colombia Chile Brazil Argentina Total 263,076 32,738 34,238 70 330,122 (42,677) (24,236) (19,685) (1,314) (7,603) (3,134) (66,913) (20,999) (10,737) (3,856) (855) (1,404) (994) (3,985) (930) (38,721) (22,705) (10,659) 152,731 (13,364) (61,161) 91,570 2,005 (11,359) 7,927 (2,695) 5,232 (325) (13) (338) (707) - (8) (983) 344 (639) (70,290) (28,697) (98,987) (9,952) (2,779) (72,093) 146,311 (61,507) 84,804 Colombia Chile Brazil Argentina Total 126,228 36,723 29,719 (29,326) (7,281) (20,674) (1,495) (36,607) (22,169) (11,690) (21,060) (459) 5,664 (29,439) 53,697 (21,479) 32,218 (897) - (29,890) (37,293) 5,594 (31,699) (5,738) (2,721) (8,459) (5,636) (1,198) - (12,785) 1,641 (558) 1,083 - - - - - - - - - - - 192,670 (55,738) (11,497) (67,235) (38,386) (2,554) 5,664 (72,114) 18,045 (16,443) 1,602 (a) Do not include Peru costs. (b) Represents accretion of ARO and other environmental liabilities. The Group believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Table 4 - Reserve quantity information Reporting rules, which were issued by the SEC at the end of 2008. Estimated oil and gas reserves The Group estimates its reserves at least once a year. The Group’s reserves estimation as of 31 December 2018, 2017 and 2016 was based on the Proved reserves represent estimated quantities of oil (including crude DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). oil and condensate) and natural gas, which available geological and DeGolyer and MacNaughton prepared its proved oil and natural gas reserve engineering data demonstrates with reasonable certainty to be recoverable estimates in accordance with Rule 4-10 of Regulation S–X, promulgated in the future from known reservoirs under existing economic and operating by the SEC, and in accordance with the oil and gas reserves disclosure conditions. Proved developed reserves are proved reserves that can provisions of ASC 932 of the FASB Accounting Standards Codification reasonably be expected to be recovered through existing wells with existing (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69 equipment and operating methods. The choice of method or combination Disclosures about Oil and Gas Producing Activities). of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and Reserves engineering is a subjective process of estimation of hydrocarbon production history. accumulation, which cannot be exactly measured, and the reserve estimation depends on the quality of available information and the GeoPark 201 interpretation and judgement of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based. The estimated GeoPark net proved reserves for the properties evaluated as of 31 December 2018, 2017 and 2016 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf ): As of 31 December 2018 As of 31 December 2017 As of 31 December 2016 Oil and Oil and Oil and condensate Natural gas condensate Natural gas condensate Natural gas (Mbbl) (MMcf ) (Mbbl) (MMcf ) (Mbbl) (MMcf ) 32,326.0 696.0 55.0 2,058.0 - 1,763.0 11,944.0 17,339.0 6,207.0 - 35,135.0 37,253.0 42,449.0 2,622.0 1,440.0 18,460.0 64,971.0 100,106.0 359.0 8,823.0 3,174.0 - 12,356.0 49,609.0 21,101.0 720.0 76.0 - 9,502.0 31,399.0 44,398.0 3,423.0 - 9,215.0 57,036.0 88,435.0 - 8,688.0 23,821.0 - - 32,509.0 - 11,329.0 - - 11,329.0 43,838.0 9,502.0 547.0 72.0 - 9,316.0 19,437.0 27,838.0 6,052 - 9,305.0 43,195.0 62,632.0 - 6,610.0 29,525.0 - - 36,135.0 - 29,690.0 - - 29,690.0 65,825.0 Net proved developed Colombia (a) Chile (b) Brazil (c) Argentina (d) Peru (e) Total consolidated Net proved undeveloped Colombia (f ) Chile (g) Argentina (h) Peru (e) Total consolidated Total proved reserves (a) Llanos 34 Block, La Cuerva Block, Yamu Block and Llanos 32 Block account for 96%, 1.5%, 1.5% and 1% (Llanos 34 Block, La Cuerva Block and Yamu Block (f ) Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% and 1% (Llanos 34 Block, La Cuerva Block and Yamu Block account for 97%, 2% account for 98%, 1% and 1% in 2017, and Llanos 34 Block and Llanos 32 and 1% in 2017, and Llanos 34 Block accounts for 100% in 2016) of the proved Block accounts for 99% and 1% in 2016) of the proved developed reserves, undeveloped reserves, respectively. respectively. (b) Fell Block accounts for 100% (Fell Block and Flamenco Block account for 98% and 2% in 2017, and Fell Block and Flamenco Block account for 99% and 1% in 2016) of the proved developed reserves, respectively. (g) Fell Block accounts for 100% (Fell Block and Flamenco Block account for 97% and 3% in 2017, and Fell Block and Flamenco Block account for 99% and 1% in 2016) of the proved undeveloped reserves, respectively. (c) BCAM-40 Block accounts for 100% of the reserves. (h) Aguada Baguales Block and El Porvenir Block account for 75% and 25% of the proved undeveloped reserves, respectively. (d) Aguada Baguales Block, Puesto Touquet Block, and El Porvenir Block account for 48%, 33% and 19% of the proved developed reserves, respectively. (e) Morona Block accounts for 100% of the reserves. 202 GeoPark 20F Table 5 - Net proved reserves of oil, condensate and natural gas Net proved reserves (developed and undeveloped) of oil and condensate: Thousands of barrels Reserves as of 31 December 2015 Increase (decrease) attributable to: Revisions (a) Extensions and discoveries (b) Purchases of Minerals in place (c) Production Reserves as of 31 December 2016 Increase (decrease) attributable to: Revisions (d) Extensions and discoveries (e) Production Reserves as of 31 December 2017 Increase (decrease) attributable to: Revisions (f ) Extensions and discoveries (g) Purchases of Minerals in place (h) Production Reserves as of 31 December 2018 Colombia 30,423.3 Chile 5,953.8 Brazil 120.0 1,148.0 (34.0) 5,779.0 6,311.0 - (5,173.3) 37,340.0 29,047.0 (7,203.0) 65,499.0 9,826.0 8,839.0 - (9,389.0) 74,775.0 - - (502.8) 6,599.0 - (347.0) 4,143.0 - - (14.0) 72.0 19.0 - (15.0) 76.0 (586.0) (6.0) 41.0 - (280.0) 3,318.0 - - (15.0) 55.0 6,315.0 (2,109.0) Argentina Peru Total - - - - - - - - - - - - 3,968.0 (470.0) - - - 36,497.1 6,893.0 6,311.0 18,621.0 18,621.0 - (5,690.1) 18,621.0 62,632.0 96.0 - - 4,321.0 29,047.0 (7,565.0) 18,717.0 88,435.0 (257.0) - - - 8,977.0 8,880.0 3,968.0 (10,154.0) 3,498.0 18,460.0 100,106.0 (a) For the year ended 31 December 2016, the Group’s oil and condensate proved reserves were revised upward by 7 mmbbl. The primary factors leading to the above were: - Better than expected performance from existing wells, resulting in an increase of 9 mmbbl, of which 8 mmbbl was from the Tigana, Jacana and other minor fields in the Llanos 34 Block, and 1 mmbbl was from the Fell Block in Chile. a change in a previously adopted development plan in the Fell Block in Chile, resulting in a 2.4 mmbbl decrease. (e) In Colombia, the extensions and discoveries are primary due to the Chiricoca, Jacamar, and Curucucu field discoveries in the Llanos 34 Block and the Tigana and Jacana field extensions in the Llanos 34 Block. (f ) For the year ended 31 December 2018, the Group’s oil and condensate proved reserves were revised upward by 9.0 mmbbl. The primary factors - Such increase was partially offset by lower average oil prices impacting the La leading to the above were: Cuerva and Yamu Blocks in Colombia, resulting in a 2 mmbbl decrease. (b) In Colombia, the extensions and discoveries are primarily due to the Jacana field appraisal wells in the Llanos 34 Block. (c) In December 2016, we obtained final regulatory approval for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement - Better than expected performance from existing wells, from the Tigana and Jacana fields in the Llanos 34 Block, resulting in an increase of 15.4 mmbbl. - The impact of higher average oil prices resulting in a 0.7 mmbbl, 1.0 mmbbl and 0.3 mmbbl increase in reserves from the blocks in Colombia, Peru and Chile, respectively. dated 1 October 2014 and its amendments were closed on 1 December 2016 - Such increase was partially offset by a decrease in reserves mainly related to following the issuance of Supreme Decree 031-2016-MEM.XXX. (d) For the year ended 31 December 2017, the Group’s oil and condensate proved reserves were revised upward by 4.3 mmbbl. The primary factors a change in a previously adopted development plan in Max, Tua, Chachalaca Sur, Tilo, and Jacamar fields in the Llanos 34 Block, resulting in a 6.3 mmbbl decrease. Also, lower than expected performance from existing wells in Fell leading to the above were: - Better than expected performance from existing wells, from the Tigana and Jacana fields in the Llanos 34 Block, resulting in an increase of 3.8 mmbbl. - The impact of higher average oil prices resulting in a 2.5 mmbbl and 0.4 mmbbl increase in reserves from the blocks in Colombia and Chile, respectively. - Such increase was partially offset by a decrease in reserves mainly related to Block, resulted in a 0.8 mmbbl decrease. Finally, revisions in Peru resulted in a 1.3 mmbbl decrease. (g) In Colombia, the extensions and discoveries are primary due to the Tigana and Jacana fields appraisal wells and the Tigui field discovery in the Llanos 34 Block. (h) Purchase of Minerals in place refers to the Aguada Baguales, El Porvenir, and Puesto Touquet fields acquisition during 2018. See Note 35.3 for further details. GeoPark 203 Net proved reserves (developed and undeveloped) of natural gas: Millions of cubic feet Reserves as of 31 December 2015 Increase (decrease) attributable to: Revisions (a) Production Reserves as of 31 December 2016 Increase (decrease) attributable to: Revisions (b) Extensions and discoveries (c) Production Reserves as of 31 December 2017 Increase (decrease) attributable to: Revisions (d) Extensions and discoveries (e) Purchase of Minerals in place (f ) Production Reserves as of 31 December 2018 Colombia Chile Brazil Argentina Total - - - - - - - - - 2,122.0 - - 36,515.0 36,158.0 5,078.0 (319.0) (5,293.0) (6,314.0) 36,300.0 29,525.0 (13,725.0) 1,187.0 59.0 - (3,745.0) (5,763.0) 20,017.0 23,821.0 544.0 3,909.0 - (679.0) - - - - - - - - - - - - 72,673.0 4,759.0 (11,607.0) 65,825.0 (13,666.0) 1,187.0 (9,508.0) 43,838.0 (135.0) 6,031.0 10,452.0 10,452.0 (3,703.0) (5,803.0) (1,071.0) (10,577.0) 2,122.0 20,767.0 17,339.0 9,381.0 49,609.0 (a) For the year ended 31 December 2016, the Group’s proved natural gas reserves were revised upwards by 5 billion cubic feet. This increase was mainly driven by better than expected performance from existing wells, primarily the Ache field in the Fell Block in Chile, resulting in an addition of 9 billion cubic feet. This increase was partially offset by a reduction of 4 billion cubic feet in resulting in a decrease of 0.7 billion cubic feet. - The above was partially offset by higher average prices that resulted in an increase of 2.5 billion cubic feet in the Fell Block in Chile. (e) The extensions and discoveries are primary due to the Jauke Field discovery in the Fell Block, in Chile, and the gas discovery of the Une Formation in the the Pampa Larga field, also in the Fell Block. (b) For the year ended 31 December 2017, the Group’s proved natural gas reserves were revised downwards by 13.7 billion cubic feet. This was the Llanos 32 Block, in Colombia. (f ) Purchase of Minerals in place refers to the Aguada Baguales, El Porvenir, and Puesto Touquet fields acquisition during 2018. See Note 35.3 for further combined effect of: details. - Removal of proved undeveloped reserves due to changes in previously adopted development plan in the Fell Block in Chile and unsuccessful proved Revisions refer to changes in interpretation of discovered accumulations and undeveloped executions in the Fell Block in Chile (totalling 21.3 billion cubic some technical and logistical needs in the area obliged to modify the timing feet). and development plan of certain fields under appraisal and development - The above was partially offset by an increase of 6.8 billion cubic feet due phases. to a better performance in the proved developed producing reserves in the Fell Block in Chile and the impact of higher average prices that resulted in an Table 6 - Standardized measure of discounted future net cash flows related to increase of 0.8 billion cubic feet. (c) In Chile, the extensions and discoveries are primary due to the Uaken Field discovery in the Fell Block. (d) For the year ended 31 December 2018, the Group’s proved natural gas reserves were revised downwards by 0.1 billion cubic feet. This was the combined effect of: proved oil and gas reserves The following table discloses estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards - Removal of proved undeveloped reserves due to changes in previously Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly adopted development plan in the Fell Block in Chile and lower than expected SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future performance from existing wells in the Fell Block in Chile (totalling 2.0 billion net cash flows were estimated using the average first day-of-the-month cubic feet). price during the 12-month period for 2018, 2017 and 2016 and using a 10% - Lower than expected performance from existing wells in BCAM-40 Block, annual discount factor. Future development and abandonment costs include 204 GeoPark 20F estimated drilling costs, development and exploitation installations and projections. It is important to point out that this information does not include, abandonment costs. These future development costs were estimated based among other items, the effect of future changes in prices, costs and tax rates, on evaluations made by the Group. The future income tax was calculated by which past experience indicates that are likely to occur, as well as the effect of applying the statutory tax rates in effect in the respective countries in which future cash flows from reserves which have not yet been classified as proved we have interests, as of the date this supplementary information was filed. reserves, of a discount factor more representative of the value of money This standardized measure is not intended to be and should not be gas. These future changes may have a significant impact on the future net interpreted as an estimate of the market value of the Group’s reserves. The cash flows disclosed below. For all these reasons, this information does not purpose of this information is to give standardized data to help the users of necessarily indicate the perception the Group has on the discounted future the financial statements to compare different companies and make certain net cash flows derived from the reserves of hydrocarbons. over the lapse of time and of the risks inherent to the production of oil and Amounts in US$ ‘000 At 31 December 2018 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows At 31 December 2017 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows At 31 December 2016 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows Colombia Chile Brazil Argentina Peru Total 4,059,619 317,437 102,104 277,429 1,352,159 6,108,748 (983,782) (156,724) (49,255) (173,053) (441,801) (1,804,615) (207,630) (848,519) (39,360) (2,515) 2,019,688 118,838 (640,625) 1,379,063 (29,008) 89,830 2,434,954 284,711 (531,751) (131,788) (187,414) (558,226) 1,157,563 (343,561) 814,002 (57,690) (656) 94,577 (19,338) 75,239 873,771 394,993 (229,593) (186,700) (69,996) (149,785) (191,096) 383,086 (113,584) 269,502 (8,344) 50,164 (14,709) 35,455 (3,752) (2,231) 46,866 (5,317) 41,549 157,527 (56,311) (7,524) (10,442) 83,250 (13,293) 69,957 200,713 (74,116) (16,352) (21,041) 89,204 (15,688) 73,516 (54,400) (293,468) (598,610) (6,610) 43,366 (8,499) 34,867 (189,922) (1,049,797) 426,968 2,655,726 (188,435) (871,884) 238,533 1,783,842 - - - - - - - - - - - - - - 1,047,540 3,924,732 (466,110) (1,185,960) (235,920) (488,548) (107,294) (676,618) 238,216 1,573,606 (147,682) (523,874) 90,534 1,049,732 941,463 2,410,940 (497,187) (987,596) (234,328) (470,461) (69,698) (290,179) 140,250 662,704 (109,321) (253,302) 30,929 409,402 GeoPark 205 Brazil Argentina Peru Total 72,316 (20,945) 16,366 542 - 2,214 (1,872) - (4,020) 8,915 73,516 (26,979) (3,000) 8,385 - - 603 7,976 9,456 69,957 (24,781) (15,170) (1,426) - - (1,879) - - - - - - - - - - - - - - - - - - - - - - - - - - - 30,929 - - 440,568 (127,235) (171,619) (34,280) 76,641 28,933 91,073 30,929 7,266 67,126 30,929 409,402 - (239,861) 69,962 (9,725) - - 383,089 (46,315) 49,574 74,717 1,133 605,764 (11,828) (256,597) 10,063 69,959 90,534 1,049,732 (21,243) - (445,776) - - - 737 - 191,288 9,611 - - (7,098) - 589,275 (10,034) 284,256 89,597 244,046 55,373 - 55,373 6,808 8,040 - - (65,585) (245,263) 19,783 172,636 41,549 34,867 238,533 1,783,842 Colombia 300,097 (91,163) (171,131) 14,941 76,641 17,302 70,180 - 3,030 49,605 269,502 (198,631) 289,199 (124,053) 49,574 67,571 Chile 68,155 (15,127) (16,854) (49,763) - 9,417 22,765 - 8,256 8,606 35,455 (14,251) 26,928 79,078 - 7,146 673,622 (69,594) (258,842) 46,060 814,002 (380,829) 397,064 (18,632) 271,933 85,880 257,540 - (185,118) 137,223 1,379,063 6,097 4,380 75,239 (18,923) 16,093 413 12,323 2,980 (4,517) - (1,368) 7,590 89,830 Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves Amounts in US$ ‘000 Present value at 31 December 2015 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Purchase of Minerals in place Net changes in income taxes Accretion of discount Present value at 31 December 2016 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Net changes in income taxes Accretion of discount Present value at 31 December 2017 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Purchase of Minerals in place Net changes in income taxes Accretion of discount Present value at 31 December 2018 206 GeoPark 20F Other Exhibit 12.1 Certification by the Principal Executive Officer Pursuant to Section 302 of a. All significant deficiencies and material weaknesses in the design or the Sarbanes-Oxley act of 2002 I, James F. Park, certify that: 1. I have reviewed this annual report on Form 20-F of GeoPark Limited; operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other 2. Based on my knowledge, this report does not contain any untrue statement employees who have a significant role in the company’s internal control over of a material fact or omit to state a material fact necessary to make the financial reporting. statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; Date: April 11, 2019 James F. Park 3. Based on my knowledge, the financial statements, and other financial Chief Executive Officer information included in this report, fairly present in all material respects the (Principal Executive Officer) financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; Certification by the Principal Financial Officer Pursuant to Section 302 of 4. The company’s other certifying officer(s) and I are responsible for I, Andrés Ocampo, certify that: establishing and maintaining disclosure controls and procedures (as defined The Sarbanes-Oxley Act of 2002 in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over 1. I have reviewed this annual report on Form 20-F of GeoPark Limited; financial reporting (as defined in Exchange Act Rules 13a 15(f ) and 15d 15(f )) for the company and have: 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the a. Designed such disclosure controls and procedures, or caused such statements made, in light of the circumstances under which such statements disclosure controls and procedures to be designed under our supervision, were made, not misleading with respect to the period covered by this report; to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, 3. Based on my knowledge, the financial statements, and other financial particularly during the period in which this report is being prepared; information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, b. Designed such internal control over financial reporting, or caused such and for, the periods presented in this report; internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial 4. The company’s other certifying officer(s) and I are responsible for reporting and the preparation of financial statements for external purposes in establishing and maintaining disclosure controls and procedures (as defined accordance with generally accepted accounting principles; in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f ) and 15d 15(f )) c. Evaluated the effectiveness of the company’s disclosure controls for the company and have: and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the a. Designed such disclosure controls and procedures, or caused such period covered by this report based on such evaluation; and disclosure controls and procedures to be designed under our supervision, d. Disclosed in this report any change in the company’s internal control over to ensure that material information relating to the company, including its financial reporting that occurred during the period covered by the annual consolidated subsidiaries, is made known to us by others within those entities, report that has materially affected, or is reasonably likely to materially affect, particularly during the period in which this report is being prepared; the company’s internal control over financial reporting; and 5. The company’s other certifying officer(s) and I have disclosed, based on internal control over financial reporting to be designed under our supervision, our most recent evaluation of internal control over financial reporting, to to provide reasonable assurance regarding the reliability of financial the company’s auditors and the audit committee of the company’s board of reporting and the preparation of financial statements for external purposes in directors (or persons performing the equivalent functions): accordance with generally accepted accounting principles; b. Designed such internal control over financial reporting, or caused such GeoPark 207 Exhibit 12.2 c. Evaluated the effectiveness of the company’s disclosure controls Certification by the Principal Executive Officer Pursuant to 18 U.s.c. and procedures and presented in this report our conclusions about the Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley effectiveness of the disclosure controls and procedures, as of the end of the act of 2002 period covered by this report based on such evaluation; and The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the d. Disclosed in this report any change in the company’s internal control over fiscal year ended December 31, 2018 (the “Report”), I, Andrés Ocampo, certify financial reporting that occurred during the period covered by the annual pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the report that has materially affected, or is reasonably likely to materially affect, Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: the company’s internal control over financial reporting; and 5. The company’s other certifying officer(s) and I have disclosed, based on the Securities Exchange Act of 1934; and our most recent evaluation of internal control over financial reporting, to 2. the information contained in the Report fairly presents, in all material the company’s auditors and the audit committee of the company’s board of respects, the financial condition and results of operations of the Company. 1. the Report fully complies with the requirements of Section 13(a) or 15(d) of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or Andrés Ocampo operation of internal control over financial reporting which are reasonably Chief Financial Officer likely to adversely affect the company’s ability to record, process, summarize (Principal Financial Officer) and report financial information; and Date: April 11, 2019 b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting. Date: April 11, 2018 Andrés Ocampo Chief Financial Officer (Principal Financial Officer) Certification by the Principal Executive Officer Pursuant to 18 U.s.c. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley act of 2002 The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the fiscal year ended December 31, 2018 (the “Report”), I, James F. Park, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, that, to the best of my knowledge: 1. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: April 11, 2019 James F. Park Chief Executive Officer (Principal Executive Officer) 208 GeoPark 20F 209 Annual Report 2018 / Board of Directors Casanare Department, Colombia BOARD OF DIRECTORS Gerald E. O’Shaughnessy | Chairman Mr. O’Shaughnessy has been our Chairman and a member of our board of directors since he co-founded the company in 2002. Following his graduation from the University of Notre Dame with degrees in government (1970) and law (1973), Mr. O’Shaughnessy was engaged in the practice of law in Minnesota. Mr. O’Shaughnessy has been active in the oil and gas business over his entire business career, starting in 1976 with Lario Oil and Gas Company. He later formed The Globe Resources Group, a private venture firm whose subsidiaries provided seismic acquisition and processing, well rehabilitation services, logistical operations and submersible pump works for Lukoil and other companies active in Russia during the 1990s.  Mr. O’Shaughnessy is also founder of BOE Midstream, which owns and operates the Bakken Oil Express, a crude by rail transloading and storage terminal in North Dakota, serving oil producers and marketing companies in the Bakken Shale Oil play. Mr. O’Shaughnessy has also served on a number of non-profit boards of directors, including the Board of Economic Advisors to the Governor of Kansas, the I.A. O’Shaughnessy Family Foundation, the Wichita Collegiate School, the Institute for Humane Studies, The East West Institute and The Bill of Rights Institute, the Timothy P. O’Shaughnessy Foundation and is a member of the Intercontinental Chapter of Young Presidents Organization and World Presidents’ Organization. Pedro E. Aylwin | Executive Director Mr. Aylwin has served as a member of our board of directors since July 2013 and as our Director of Legal and Governance since April 2011. From 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance and legal matters. Mr. Aylwin holds a degree in law from the Universidad de Chile and an LLM from the University of Notre Dame. Mr. Aylwin has extensive experience in the natural resources sector. Mr. Aylwin is also a partner at the law firm Aylwin, Mendoza, Luksic, Valencia Abogados in Santiago, Chile, where he represented mining, chemical and oil and gas companies in numerous transactions. From 2006 until 2011, he served as Lead Manager and General Counsel at BHP Billiton, Base Metals, where he was in charge of legal and corporate governance matters on BHP Billiton’s projects, operations and natural resource assets in South America, North America, Asia, Africa and Australia. Carlos A. Gulisano | Non-Executive Director Mr. Gulisano has been a member of our board of directors since June 2010. Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate degree in petroleum engineering and a PhD in geology from the University of Buenos Aires and has authored or co-authored over 40 technical papers. He is a former adjunct professor at the Universidad del Sur, a former thesis director at the University of La Plata, and a former scholarship director at the national technology research council in Argentina. Dr. Gulisano is a respected leader in the fields of petroleum geology and geophysics in South America and has over 35 years of successful exploration, development and management experience in the oil and gas industry. In addition to serving as an advisor to GeoPark since 2002 and as Managing Director from February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. and has led teams credited with significant oil and gas discoveries, including those in the Trapial field in Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador, Colombia, Venezuela, Brazil, Chile and the United States. Juan Cristóbal Pavez | Non-Executive Director Mr. Pavez has been a member of our board of directors since August 2008. He holds a degree in commercial engineering from the Pontifical Catholic University of Chile and an MBA from the Massachusetts Institute of Technology. He has worked as a research analyst at Grupo CB and later as a portfolio analyst at Moneda Asset Management. In 1998, he joined Santana, an investment company, as Chief Executive Officer, where he focused mainly on investments in capital markets and real estate. While at Santana, he was appointed Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s main assets. Since 2001, he has served as Chief Executive Officer at Centinela, a company with a diversified global portfolio of investments, with a special focus in the energy industry, through the development of wind parks and run-of-the-river hydropower plants. Mr. Pavez is also a board member of Grupo Security, Vida Security and Hidroelétrica Totoral and founder board member of several companies, including Quintec, Enaex, CTI and Frimetal. 210 Annual Report 2018 Robert A. Bedingfield | Non-Executive Director Mr. Bedignfield has been a member of our board of directors since March 2015. He holds a degree in Accounting from the University of Maryland and is a Certified Public Accountant. Until his retirement in June 2013, he was one of Ernst & Young’s most senior Global Lead Partners with more than 40 years of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices, as well as serving on Ernst & Young’s Senior Governing Board. He has extensive experience serving Fortune 500 companies; including acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times an Executive Committee Member, and the Audit Committee Chair of the University of Maryland at College Park Board of Trustees. Mr. Bedingfield served on the National Executive Board (1995 to 2003) and National Advisory Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield has also served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). Jamie B. Coulter | Non-Executive Director Mr. Coulter has been a member of our board of directors since May 2017. He currently serves as Chairman and CEO of Coulter Enterprises Inc., a private investment firm and has been an investor in and supporter of GeoPark since 2006. He built and became the CEO of Lone Star Steakhouse & Saloon, a company that was awarded IPO of the year and Forbes Magazine #1 Best Small Company in America for 3 consecutive years. He developed and operated Pizza Hut and Kentucky Fried Chicken restaurants and became the largest Pizza Hut franchisee, was inducted to the Pizza Hut Hall of Fame, and was named the Restaurants & Institutions CEO of the year. Mr. Coulter has both operating and investment experience in the oil and gas business, including, the founding of Sunburst Exploration, a US upstream oil and gas company and also has a successful track record as an oil and gas investor in the North American shale plays. Mr. Coulter currently serves as a Director of the Federal Law Enforcement Foundation; Director of Jimmy Johns, LLC; Director of Realm Cellars; Director of Cirq Estates, LLC; Director of KB Wines, LLC; Member of the Board of Trustee for HCA Wesley Medical Center and Member of the Texas Heart Institute Foundation Board. Constantin Papadimitriou | Non-Executive Director Mr. Papadimitriou has been a member of our board of directors since May 2018. Mr. Papadimitriou holds an Economics and Finance degree from Geneva University and post graduate Diploma in European Studies also from Geneva University. Mr. Papadimitriou is a respected and successful international investor and businessman, with more than 30 years of investment experience in global capital markets and in resource and industrial projects. Mr. Papadimitriou was one of the original “friends and family” investors in GeoPark in its early days in 2004. Mr. Papadimitriou is currently CEO of General Oriental Investments S.A., the Investment Manager of the Cavenham Group of Funds. Previously he was CEO of Cavamont Geneva. During his tenure at the Cavamont group, Mr. Papadimitriou was responsible for Treasury Management, the Private Equity Portfolio as well as representing the group on the Boards of associated companies including investments in the oil and gas, mining, real estate and gaming sectors (including Basic Petroleum, a Nasdaq-listed Guatemalan oil and gas company). Mr. Papadimitriou is also founding partner of Diorasis International, a company focusing on investments in Greece and the broader Balkans and he also chairs the Greek language school of Geneva and Lausanne. James F. Park | Chief Executive Officer and Deputy Chairman Mr. Park has served as our Chief Executive Officer and as a member of our board of directors since co-founding the Company in 2002 and has led the Company´s expansion into Chile, Argentina, Colombia, Brazil and Peru. He has extensive experience in all phases of the upstream oil and gas business, with a strong background in the acquisition, implementation and management of international joint ventures in North America, South America, Asia, Europe and the Middle East. He holds a degree in geophysics from the University of California at Berkeley and has worked as a research scientist in earthquake studies at the University of Texas. Mr. Park helped pioneer the development of commercial oil and gas production in Central America, as a senior executive of Basic Resources International where he remained as a board member until the company was successfully sold in 1997. Mr. Park has experience in the development of grass-roots exploration activities, drilling and production operations, surface and pipeline construction and crude oil marketing and transportation, and with legal and regulatory issues, and raising substantial investment funds. Mr. Park is also a member of the board of directors of Energy Holdings and has served on various non-profit organizations, including as a board member of S.E.E. International. Mr. Park is a member of the AAPG and SPE and has lived in Latin America since 2002. 211 Annual Report 2018 / Management Team REC-128 Block, Praia Dos Castelhanos, Brazil MANAGEMENT TEAM JAMES F. PARK Chief Executive Officer MARCELA VACA Colombia SALVADOR MINNITI Exploration AGUSTINA WISKY Capacities & Culture AUGUSTO ZUBILLAGA Chief Operating Officer ALBERTO MATAMOROS Argentina, Chile CARLOS MURUT Reserves & Development GUILLERMO PORTNOI New Business ANDRÉS OCAMPO Chief Financial Officer BARBARA BRUCE Peru MARTÍN TERRADO Operations & Safety STACY STEIMEL Shareholder Value PEDRO E. AYLWIN Legal & Governance LIVIA VALVERDE Brazil NORMA SÁNCHEZ Social & Environment ADRIANA LA ROTTA Connections Our Offices Argentina Buenos Aires Office Florida 981 – 1st floor C1005AAS Buenos Aires + 54 11 4312 9400 Chile Santiago Office Brazil Rio de Janeiro Office Registered Office Cumberland House 9th floor, 1 Victoria Street Praia de Botafogo, 288, Bloque A, Sala Hamilton HM11 - Bermuda 801, Botafogo, Río de Janeiro + 55 21 3078 7475 Peru Lima Office Corporate Secretary Pedro E. Aylwin Independent Auditors Price Waterhouse & Co. S.R.L. Bouchard 557, 8th floor Buenos Aires Argentina Petroleum Consultant DeGolyer and MacNaughton Counsel to the Company 5001 Spring Valley Road Suite 800 East Nuestra Señora de los Ángeles 176 Av. Santa Cruz 300, San Isidro, Lima as to New York Law Dallas, Texas 75244 Las Condes, Santiago + 56 2 242 9600 Punta Arenas Office Lautaro Navarro 1021, Punta Arenas Magallanes Region + 56 61 745 100 Colombia Bogota Office Street 94 N° 11-30, 8th floor Bogota + 57 1 743 2337 + 51 1 713 6100 Davis Polk & Wardwell LLP USA England London Office 18 Upper Brook St., 5th floor London W1K 7PU + 44 207 629 8466 Spain Madrid Office Calle Jorge Juan 8, 3H Madrid 28001 + 34 91 104 83 93 450 Lexington Avenue New York, NY 10017 USA Solicitors to the Company as to Bermuda Law Cox Hallett Wilkinson Cumberland House 9th floor, 1 Victoria Street Hamilton HM11 - Bermuda P.O. Box HM 1561 Hamilton HMFX - Bermuda Registrar Computershare Investor Services Queensway House 480 Washington Blvd. Jersey City, NJ 07310 213 Annual Report 2018 Jacana Field, Llanos 34 Block, Colombia Challacó Bajo, Neuquén Province, Argentina ANNUAL REPORT 2018 WWW.GEO-PARK.COM 

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