Geopark Ltd
Annual Report 2017

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ANNUAL REPORT 2017 EXPLORER OPERATOR CONSOLIDATOR CONTENTS Bottom Line Letter to Shareholders 1 4 16 Business Approach & Guidelines 22 24 25 27 2017 Performance Our Strengths Our Platform Our Approach 28 Our Value System 31 Form 20-F 156 Consolidated Financial Statements 208 209 Board of Directors Corporate Management Team, Secretary & Advisors BOTTOM LINE Oil and Gas Production 25 20 15 10 5 0 ) d / e o b M ( n o i t c u d o r P y l i a D e g a r e v A 2011 2012 2013 2014 2015 2016 2017 Oil and Gas Reserves 150 120 90 60 30 0 ) e o b M M ( s e v r e s e R P 2 2011 2012 2013 2014 2015 2016 2017 Gas Oil Gas Oil Magallanes Region, Chile “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” GeoPark 3 LETTER TO SHAREHOLDERS Dear Fellow Shareholders: Más Cash / Capital Strength We are pleased to report that our GeoPark team again outperformed Differentiating us from most of our industry peers, GeoPark is a self- in 2017 – making us a better, stronger, more capable, and more funding growing cash-generating company - meaning our own cash valuable Company than ever before. flows are sufficient to pay for and expand our business. Cash flows from operating activities were up 72% to $142 million and Adjusted The international investment community began taking increased EBITDA more than doubled to $176 million. We also successfully notice of our enduring growth track record and GeoPark was the best lowered borrowing costs and extended debt maturities by issuing performing upstream oil and gas company on the New York Stock a new bond for $425 million, at 6.5% due in 2024, and which was Exchange in 2017 with a 130% share price increase. substantially oversubscribed by top tier international investors. We closed 2017 with $135 million in cash. A continuous theme of GeoPark is ‘Vamos por Más’ (‘Let’s Go for More’) and our 2017 performance delivered más (more) in all key Más Value fundamentals of our business: With our new oil and gas discoveries in 2017 and increasingly-efficient Más Oil and Gas cost structure, the independently-certified net present value (NPV) of GeoPark’s 2P oil and gas reserves increased by 21% to a value of $2.3 Success in our industry begins by being able to consistently find, billion (despite using lower price decks compared to 2016). Last year develop and produce oil and gas. Last year, GeoPark extended its we invested $106 million and increased our NPV by $404 million. On exceptional 15 year growth track record and increased production a ‘per share’ basis and deducting outstanding net debt and minority by 23% to a record 27,586 boepd with an exit production of 31,977 interests, our net debt adjusted 2P NPV per share increased by 24% boepd. In Colombia, production grew by 39% to 21,787 boepd. After to $29.2 per share (or $15.8 per share for Colombia alone). This means producing over 10 million boe during the year, we replaced and grew our market share price is still significantly below the underlying value our certified oil and gas reserves with proven (1P) reserves increasing of our oil and gas assets. by 24% to 97 million boe and total proven and probable (2P) reserves increasing by 11% to 159 million boe. In Colombia, 2P reserves Más Acreage / Upside increased by 31% from the continuing extension of the large Tigana GeoPark has steadily and economically built an extensive land and Jacana oil fields. position across Latin America – with more than five million acres in 29 blocks in 9 proven hydrocarbon basins in 5 countries, consisting Más Efficiencies / Lower Costs of a risk-balanced mix of production, development, exploration and Being the safest lowest-cost driller and producer of oil and gas are unconventional resource projects. This large acreage platform is one the critical factors in achieving long-term industry leadership and of our most powerful assets – one that does not show up on a balance economic success - with an even greater emphasis in today’s world sheet – but which provides the foundation for long-term growth. of oil price volatility. GeoPark’s operational strength has allowed us On our acreage, GeoPark has identified new geological plays and to relentlessly drive down capital and operating costs to achieve top- prospects – that is, new potential oil and gas fields – with audited performing metrics, with 2P finding and development costs of $4.0 exploration resources of 700 million to 1.3 billion boe. per boe (consolidated) and $2.8 per boe (Colombia), and operating costs of $7.3 per boe (consolidated) and $4.3 per bbl (Colombia Llanos Más Opportunity 34). Our passion for cost efficiency has resulted in 90% of GeoPark’s One of the pillars of GeoPark’s business plan is our success in production being cash flow positive at oil prices of just $25-30 per identifying and acquiring new high-quality projects on attractive barrel. terms. Our continuous efforts to uncover new business opportunities over the last 10+ years in targeted hydrocarbon basins has built a 4 Annual Report 2017 / Letter to Shareholders GeoPark 5 6 Annual Report 2017 / Letter to Shareholders Jacana Field, Llanos 34 Block, Colombia $2+ billion new project inventory in Colombia, Brazil, Argentina, Peru, forward regardless of any short-term cycles or sentiment. We believe Ecuador and Mexico – with an active focus on initiatives with Latin our strength and unique position across the region today results from American national oil companies. In early 2018, GeoPark entered into this alignment and gives us even more advantages in achieving our a new acquisition partnership with ONGC, the national oil company ambitious goals. of India, to support and join our efforts to expand our upstream portfolio across Latin America. Más Capabilities People As our history has proved, great people create great results. We are Our big ambitions require us to prepare for our future by pleased to recognize and thank the women and men who have built continuously investing in our capacities and know-how and to and are continuing to build GeoPark. They are our heart and engine, become the best at every component of our business. Last year we and have faced and met every challenge with a professionalism, continued to invest in our technical, financial and management creativity and agility that keeps propelling us forward. excellence and strengthen our country business unit teams, including new leadership in Peru and Argentina. This includes dynamically As an entrepreneurial and battle-tested company that has grown structuring our organizational and leadership framework to more from scratch into one of Latin America’s leading independents, we effectively manage our growing enterprise and capture the future. attribute our success to a proud culture based on trust – and which is the catalyst for our continuous record of safe, clean, neighborly, Más Safe, Clean and Neighborly Operations transparent and successful operations. Our in-house-designed value system called SPEED is GeoPark’s competitive advantage. SPEED represents our character, guides our Our gratitude extends to the persistently supportive families of all behavior and defines our success. It creates positive interdependence our team members who have contributed immensely to where we with the communities where we operate and ensures safe and have been and where we are going. We were fortunate to join with all environmentally-clean operational performance – with the goal to be employees and spouses this year for GeoPark’s Fifteenth Anniversary the partner-of-choice, employer-of-choice and neighbor-of-choice. to express our thanks personally and to celebrate together our From 2015 to date, GeoPark is the only major operator in Colombia powerful culture, impressive accomplishments and big expectations with zero work interruptions. In 2017, GeoPark was awarded the ISO for each other. 14001 environmental management certification in Colombia. Vision and Alignment As described in our Business Guidelines which accompany every Annual Report, GeoPark’s long-term value proposition is to build the leading oil and gas independent company in Latin America – a A special thanks also to our hard-working Board of Directors. We are saddened by the unfortunate passing of Peter Ryalls and Michael Dingman and sincerely grateful for their important and valuable contribution to our Company. region of unlimited hydrocarbon resources, a welcoming business environment, and little competition. An advantage in creating our Business Platform GeoPark’s business plan follows a technical approach to identify Company has been a consistent long-term vision and conservative high-value under-exploited proven hydrocarbon basins – based on business plan that are supported and shared by our shareholders, geological, infrastructure and regulatory factors. We then work to Board of Directors, management and employee team. establish strategic positions in the targeted regions. Our systematic expansion to date has resulted in building stable and growing It is our steady focus on this bigger prize that has allowed us to build businesses in Colombia, Chile, Brazil, Argentina and Peru. Each the foundation and tools needed for the long-term and to push country is managed by reputable and professional local teams, with Jacana Field, Llanos 34 Block, Colombia GeoPark 7 supporting production and cash flows, attractive underlying reserves commitment to drill two exploration wells in 2018. and resources, and inventories of new project opportunities. Our independent country businesses are further enhanced by being Argentina Business supported by an overall corporate organization, which improves Our team is continuing to strengthen our position in Argentina, efficiencies, reduces costs through operational and financial where it has a proven history of exploration success. synergies, controls quality, drives performance, and more effectively grows our overall company by allocating capital to the best In August 2017, we made a successful new light oil field discovery shareholder value-adding projects. with the Rio Grande Oeste exploration well in the CN-V Block in the Briefly looking at each of our businesses: Colombia Business Neuquen Basin. An adjacent prospect will be drilled in 2018. In December 2017, GeoPark acquired a 100% working interest in and operatorship of three new blocks (Aguada Baguales, El Porvenir and GeoPark is leading the strongest upstream project in Colombia and Puerto Touquet) in the heart of the Neuquen Basin with production, one of the most attractive onshore projects in Latin America today. development, exploration and unconventional resource potential. In less than five years we grew from zero to be the third largest oil The blocks are currently producing 2,400-2,500 boepd and were operator in the country – and are currently proving up what is being acquired at a value of $4 per boe 2P reserves. In addition to its called the largest oil field discovery in Colombia in the last 20 years. attractive upside potential, this acqusition represents a good fit with our existing platform in Argentina with cost savings and operational Our key asset is the Llanos 34 Block (GeoPark operated), which we synergies. have grown from 0 to 50,000+ bopd gross production. During 2017, following successful appraisal drilling in the Tigana and Jacana oil Peru Business fields and new oilfield discoveries – Curucucu, Chiricoca, and Jacamar GeoPark continues working to prepare for the development of the – we materially increased our Colombian certified 1P and 2P reserves Morona Block. This project has become emblematic for Peru and by 64% and 31% to 66 million boe and 88 million boe respectively. represents PetroPeru’s return to upstream activity. GeoPark was Our 2P reserve life index reached 11 years and the reserve selected as the partner-of-choice and awarded the operatorship with replacement ratio was 360%. Our 1P NPV and 2P NPV in Colombia a 75% working interest. We recently signed a cooperation agreement increased to $1.1 billion and $1.4 billion respectively. with the local indigenous communities to work together to complete the Environmental Impact Assessment which is expected to be Llanos 34 is a highly-attractive, low risk, low cost and high netback submitted in 2018. block which provides a large scale profitable production base even in low oil price environments. Due to the expertise of our local teams, Morona is a large block in the proven Maranon Basin with a large net finding and development costs (F&D costs) for 2017 were just $2.4 upside potential (approximately 320-500 million boe) with several per boe (1P). We have a big inventory of well sites (75+) to continue high impact plays and prospects. The block’s key asset is the Situche growing production, with IRRs exceeding 500% and six-month Central oil field, which was discovered and proven up by two wells paybacks (assuming a $50 per barrel Brent oil price). Our economics (which tested at a combined rate of 7,500 bopd), and which has and return on capital in Llanos 34 are highly profitable and beat certified gross 3P reserves of 83 million barrels, a big 200 million almost any North American conventional or unconventional play. barrel potential, and the opportunity for near-term cash flow. Morona In a constant effort to reduce transportation costs and improve increases our overall inventory of reserves and exploration resources netbacks, we are constructing a new 30 km flow line to connect and can contribute to our long-term durable growth. GeoPark has Llanos 34 to the main Colombian pipeline infrastructure. designed a phased work program that is expected to put the Situche represents an important acquisition for GeoPark that significantly Central field into production initially through a long-term test to During 2017, GeoPark also acquired attractive exploration acreage begin generating cash flow – with ‘first oil’ targeted for 2019. (Tiple and Zamuro), adjacent to Llanos 34, by farming-in with a 8 Annual Report 2017 / Letter to Shareholders Magallanes Region, Chile GeoPark 9 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 8 exploration blocks in onshore mature proven hydrocarbon basins (Potiguar, Reconcavo, and Sergipe Alagoas). GeoPark will drill 2-3 exploration wells in 2018 to continue testing this potential. GeoPark also has identified attractive onshore hydrocarbon opportunities in Brazil and is working with Petrobras in its divestment efforts with the objective of expanding our asset base. Chile Business We are Chile’s first private oil and gas producer. We built the business from a flat-footed start-up in 2006 to a solid business with current production of approximately 2,900 boepd (66% gas, 34% oil), 2P reserves of 34 million boe and 5 blocks with 0.8 million acres, consisting of approximately 375-700 million boe of exploration and unconventional resources. Over 20 million boe have already been produced by GeoPark in Chile and we divested 20% of our project in 2011 for approximately $150 million. Our Chilean team has done an excellent job improving efficiencies and maintaining production stability with very little new investment. Production and reserves decreased in 2017 due the natural decline of the fields and limited drilling activity since the end of 2014. In early 2017, GeoPark extended its gas off-take contract with Methanex to 2026 to supply its large methanol plant in Punta Arenas. In early 2018, GeoPark drilled and tested a new shallow El Salto formation prospect and discovered the Uaken gas field; which creates a new low cost gas play across the Fell Block. 10 Annual Report 2017 / Letter to Shareholders New Projects and Countries With our focus on achieving scale, GeoPark is always in the hunt to acquire attractively-valued new oil and gas upstream opportunities across Latin America and we have built an impressive inventory of new projects over the last ten years. Following the lower oil price environment, national oil companies, which control the biggest and best hydrocarbon acreage, are reevaluating their portfolios and initiating divestment programs. Our regional platform, expertise and reputation give us first mover advantage in potentially acquiring these attractive projects. We are also working towards establishing new platforms in Mexico and Ecuador, where regulatory reforms have opened the door for private companies to access highly attractive hydrocarbon assets – many of which are an excellent fit for GeoPark’s skill set. As a result of our existing large and diversified organic asset portfolio, GeoPark has the advantage of being a patient asset acquirer, and can wait for the right market opportunities to acquire the right projects at the right prices. To enhance our position as the preferred buyer in the region, we have also created strategic acqusition partnerships with strong players, such as ONGC from India. Tua Field, Llanos 34 Block, Colombia GeoPark 11 Outlook As a Company, GeoPark is built to prosper in a $40-45 oil price world. The current increased price environment allows us to further expand our programs and achieve greater returns – while maintaining our inherent discipline and focus on cost and value. Our 2018 work and investment program targets a $140-150 million capital investment program (considering Brent oil prices of $60 per barrel), and is fully funded by operating cash flows. The work program provides for a 40+ well drilling program targeting production growth of 25-30% (including the new Argentine assets) and an exit production of 38,000-39,000 boepd, and includes: • 29-31 gross well development, appraisal and exploration drilling program and new flowline construction in the Llanos 34 and adjacent blocks in the Llanos Basin in Colombia • 6-7 gross well exploration drilling program in the Neuquen Basin in Argentina • Environmental impact assessment and preliminary engineering and facility work on the Morona Block in the Maranon Basin in Peru • 2-3 gross well exploration drilling program in the onshore Reconcavo and Potiguar Basins in Brazil • 1-2 gross well exploration and development drilling program on the Fell Block in the Magallanes Basin in Chile GeoPark has developed and proven-up a highly-effective capital allocation methodology to manage its five country portfolio. This system enables us to review and select from a wide range of projects generated by each business unit team with different returns, potentials, risks, sizes, timelines and geographies. It ensures that capital is always directed to our top value-adding projects after ranking them on technical, strategic and economic criteria. It creates a healthy competition between our different business units which further helps drive performance. It also provides greater security in volatile markets by allowing us to easily add or remove projects depending on oil prices and project performance – and to fine-tune our desired risk exposure. 12 Annual Report 2017 / Letter to Shareholders Magallanes Region, Chile GeoPark 13 Thank You Our sincere thanks and appreciation to our shareholders and bondholders – old and new alike – who have partnered with us, believe in our project, and support our efforts. In 2017, we continued our campaign to reach out to new investors 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 stock performer last year and our stock trading volumes have begun to accelerate (now at levels exceeding $5 million per day) which has opened up shareholder participation to the wider investment community. As always, your comments and recommendations are welcomed and 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. We look forward to delivering and reporting to you on our results in 2018. Sincerely, Gerald E. O’Shaughnessy Chairman James F. Park Chief Executive Officer 14 Annual Report 2017 / Letter to Shareholders 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 and resources in new geological play types and formations. 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 regions Much of the world still lacks adequate energy supplies for the most 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 oil exciting technologies and sources are being developed, oil and gas companies, with the presence of only a modest number of more- is the most reliable energy source and will be required to support agile independent companies. North America is home to thousands over half of our planet’s continuous and rising energy needs far into of independent oil and gas operators, whereas Latin America, an this century. area substantially larger and with greater resource potential, has only a handful of independents taking advantage of available We believe the best places for us to find and develop hydrocarbons opportunities. In contrast to many areas of the world, the are in areas around the world where oil and gas have already been environment and resources for operating and funding a business discovered, but which for economic, technical, funding or other are welcoming and increasingly more feasible. Furthermore, 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 2017 / Business Approach and Guidelines 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 it organizational, market, price, partner, shareholder, regulatory and 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 The founders and our management team have a substantial part of volatility of 2015-2016. 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 teams. other shareholder other than our salaries and stock performance 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 the 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 undertaking of risk in search of significant rewards. To succeed, an professionals and teams with respected reputations. They know both oil and gas company must effectively identify and manage the specific subsurface rocks and conditions and the above-ground prevailing risks and uncertainties to capture the available rewards. operating and business environments in each region and give us the We believe this to be one of GeoPark’s key capabilities; and our characteristics of a local company. Our pride and care in how we act Casanare Department, Colombia GeoPark 17 and perform in our home regions are key elements of 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 by hydrocarbons in the subsurface, but also the muscle and experience being tied together by an overall corporate organization, which to get the oil and gas out of the ground and profitably to market. improves efficiencies, reduces costs with operational and financial Our attractive asset portfolio is evidence of our ability to acquire synergies, controls quality, and can more effectively raise capital for good projects in the right basins in the right countries with the right our projects. It is also a source for new technologies and ideas to partners and at the right price. spread from one region to another. For example, our team introduced a new geological play-type to the Llanos Basin in Colombia (an Today, we have an amazing team of employees from Chile, Colombia, area that has been explored for more than 75 years) that resulted Brazil, Peru and Argentina – each of whom joined GeoPark with the in multiple new oil field discoveries, and new oil technology to the purpose of building a unique and special company that is prepared 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 most The international upstream oil and gas business is not for the 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 attractive others have given-up or failed. This is the engine and fire of our investment vehicle for all our shareholders – with a strong foundation growth and the true long-term intangible value of our Company. to minimize any downside, a big upside through multiple growth We are immensely grateful to all these men and women for their opportunities, and an overall organizational system to more professionalism, discipline, unity and heart. 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, 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 of 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 skill sets – as Explorers, Operators and Consolidators – which we a long-term and continuous effort and we have been building an 18 Annual Report 2017 / Business Approach and Guidelines Tua Field, Llanos 34 Block, Colombia GeoPark 19 20 Annual Report 2017 / Business Approach and Guidelines Morona River, Morona Project, Peru attractive inventory of new projects in the region over the last ten by succeeding equally in each of these interdependent areas can we years, aided by our team’s 25+ year experience in Latin America. realize our overall success and ambitions. This is important in every Our focus is always to build a larger scale balanced portfolio that the most effective governance, full compliance and consistent includes lower-risk short term cash flow generating properties, mid- transparency with all relevant authorities. Not only does this allow term medium-risk development projects, and longer-term higher- us to be a more successful business enterprise over the long-term, risk big upside projects. This permits steady secure growth with an it reflects our pride in carrying out an important mission in the right opportunity for accelerated high growth ‘home-runs’ from the bigger way. The men and women of GeoPark care passionately about how country where we operate, and we make every effort to achieve projects. our Company acts – both internally and externally – and we all consider our culture to be our core asset and the prime source of our Good oil and gas partners are a key element of our new business past success and future opportunity. efforts and we like to balance our acquisition risk by including experienced partners in our new projects. We have developed a long- The world is continuously moving in a more regulated direction term strategic alliance with ONGC to build a portfolio of upstream with higher expectations, and to be able to operate in this new assets across Latin America and the International Finance Corporation environment is a fundamental part of business today. We believe that (IFC) of the World Bank is a long-term principal shareholder of (and GeoPark’s ability to meet these challenges and perform to or beyond sometimes lender to and working interest partner of ) GeoPark. We these ever increasing standards represents a competitive advantage also have developed long-term relationships with the national oil for the future. For example, the manner of, results from, and impact companies where we operate, such as ENAP in Chile, Ecopetrol in on the communities of our overall work in Chile and Colombia Colombia, Petrobras in Brazil, YPF in Argentina and Petroperu in Peru. provided the rationale and support for the government and regional community to allow us to expand our project into new areas. It Critical to the success of any new project is to conduct a thorough can also be meaningful and fun, such as with our full scholarships technical and economic analysis prior to acquiring any new asset. targeting young women, in the local communities near our field We make sure we understand the project, its risks and its value – operations, for training in the sciences. and we buy right. It is difficult to turn a faulty or overpriced project into a good business. Following intensive geological, geophysical, The IFC of the World Bank, our long time shareholder, has been a engineering, operational, legal and financial analyses and due constructive force in helping us operate and manage our business in diligence, we perform a detailed discounted cash flow (DCF) consideration of the environment and communities around us. The valuation. We also consider the option value or strategic benefits IFC further assists us by carrying out annual audits and physical site of a project when entering a new region. We do not buy assets on visits of both our regulatory compliance and best-practices approach. 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. Culture ‘Creating Value and Giving Back’ is our motto and represents GeoPark’s market-based approach to align our business objectives with our core values and responsibilities. Our in-house designed program, titled SPEED, targets and integrates the critical elements – Safety, Prosperity, Employees, Environment and Community Development – necessary to make our total business plan work. Only - James F. Park (2008*) Morona River, Morona Project, Peru GeoPark 21 2017 PERFORMANCE Record Oil and Gas Production • Production up 23% to 27,586 boepd. Record Capital Investment and Costs Efficiencies • 2P Finding and development costs: New Opportunities • Argentina: low-cost, cash flow-producing acquisition in the prolific Neuquen basin • Colombia production up 39% to 21,788 Consolidated $4.0/boe; Colombia $2.8/boe. with production, development, exploration bopd. • Operating netback/capital expenditure ratio and unconventional opportunities. • Record exit production of 31,977 boepd. of 2.2x. • Colombia: Tiple and Zamuro high-impact Record Oil and Gas Reserves • 1P reserves up 24% to 97.0 million boe. • 2P reserves up 11% to 159.2 million boe. • Colombia 2P reserves up 31% to 88.2 million boe. • Capital investment program of $105.6 exploration acreage added adjacent to million generated $404 million in 2P NPV10. Llanos 34 Block. • OPEX: $7.3 per boe, Colombia $5.6 per boe. • Long-term Latin American acquisition partnership with ONGC (India’s national oil company). Record Cash Flow/EBITDA Growth • Adjusted EBITDA up 124% to $175.8 million. • Operating Netback up 87% to $228.3 million. 2018 Outlook • Capital investment program of $140-150 • Cash Flow from operations up 72% to $142.2 million. Record Oil and Gas Asset Valuation • 1P reserve NPV10 up 38% to $1.5 billion. • 2P reserve NPV10 up 21% to $2.3 billion. • 2P reserve Colombian assets NPV10 up 38% to $1.4 billion. million. Strengthened Balance Sheet and Credit Rating • $134.8 million of cash in hand. • Net debt adjusted 2P NPV10 increased by • new $425 million 2024 bond issued, with 24% to $29.2 per share. longer maturities and lower cost. • Drilling program of 40+ exploration, appraisal and development wells in Colombia, Argentina, Brazil and Chile. • Targeted production growth of 25-30% (including Argentina) and exit production of 38,000-39,000 boepd. • Net debt to Adjusted EBITDA ratio decreased from 3.6x to 1.7x. • Upgraded credit rating to B+ with a stable outlook. 2006 2007 2008 2009 2010 2011 22 Annual Report 2017 / Performance Oil Gas 2012 2013 2014 2015 2016 2017 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 0 ) 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 GeoPark 23 Know-How Strong Team, Capabilities, Approach and Culture. Capital Supporting Cash Flow, Access to Funding and Strategic Partners. Track Record Consistent Operational and Financial Growth / Ability to Unlock Value from Assets. Assets Diversified Risk-Balanced Asset Base with Proven Value, Scale and Upside. OUR STRENGTHS 24 Annual Report 2017 / Our Strengths MEXICO COLOMBIA 88.2 MMBOE PERU 31.5 MMBOE CHILE 34.0 MMBOE OUR PLATFORM BRAZIL 4.4 MMBOE GeoPark 25 ARGENTINA 1.1 MMBOE Latin American Platform 2P Reserves (Dec. 2017) Production Assets Development Assets Exploration Assets Unconventional Resource Assets New Project Opportunities 26 Annual Report 2017 / Our Approach Jacana Field, Llanos 34 Block, 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. Jacana Field, Llanos 34 Block, Colombia GeoPark 27 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 Community Development GeoPark is committed GeoPark is committed GeoPark is committed GeoPark is committed GeoPark is committed to creating a safe and to delivering significant to creating a motivating to minimizing the impact to being the preferred healthy workplace. bottom-line financial workplace for employees. of our projects on neighbor and partner Simply speaking, value to our shareholders. With today’s shortage the environment. by creating a mutually everybody must return Only a financially-healthy of capable energy As our footprint becomes beneficial exchange home everyday safe company can continue professionals, the cleaner and smaller, with the local and sound. to grow, attract needed company which is able the more areas and communities where we resources and create real to attract, protect, retain opportunities will be work. Unlocking local long-term benefits. and train the best team opened up for us to knowledge creates and 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. 28 Annual Report 2017 / Our Value System GeoPark 29 HIGHLIGHTED SECTIONS 42 62 106 126 134 156 Risk Factors Information on the Company Operating and Financial Information Directors and Management Major Shareholders and Related Parties Consolidated Financial Statements 30 Annual Report 2017 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, 2017 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. Common shares: 60,596,219 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. 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 Yes No 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 31 Table of Contents PRESENTATION OF FINANCIAL AND OTHER INFORMATION FORWARD-LOOKING STATEMENTS PART I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS A. Directors and senior management B. Advisers C. Auditors ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE A. Offer statistics B. Method and expected timetable ITEM 3. KEY INFORMATION A. 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 32 GeoPark 20-F 33 36 37 37 37 37 37 37 37 37 37 37 41 41 42 62 62 64 106 106 106 106 106 121 125 125 125 125 126 126 126 130 132 133 133 134 134 134 136 136 136 137 137 137 137 137 137 137 137 ITEM 10. ADDITIONAL INFORMATION A. Share capital B. Memorandum of association and bye-laws Enforcement of Judgments C. Material contracts D. Exchange controls E. Taxation F. Dividends and paying agents G. Statement by experts H. Documents on display I. Subsidiary information ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 137 137 137 143 143 144 144 146 146 146 146 146 ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 146 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 146 146 146 146 147 147 147 147 147 147 147 147 147 147 147 147 147 148 148 148 148 148 149 150 150 150 150 152 157 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 2020” are to our 2013 issuance of US$300.0 million aggregate principal amount of 7.50% senior secured notes due 2020; • “Notes due 2024” are to our 2017 issuance of US$425.0 million aggregate principal amount of 6.50% senior secured notes due 2024; • “US$” 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 33 Financial statements Non IFRS financial measures Our consolidated financial statements Adjusted EBITDA This annual report includes our audited consolidated financial statements as Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by of December 31, 2017 and 2016 and for each of the years ended December 31, management and external users of our financial statements, such as industry 2017, 2016 and 2015 (hereinafter “Consolidated Financial Statements”). analysts, investors, lenders and rating agencies. 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 Price unrealized gains in commodity risk management contracts and bargain Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers purchase gain on acquisition of subsidiaries. Adjusted EBITDA is not a measure Network (“PwC”), an independent registered public accounting firm, as stated of profit or cash flows as determined by IFRS. exploration and evaluation assets, accrual of stock options and stock awards, in their report included elsewhere in this annual report. Our fiscal year ends December 31. References in this annual report to a fiscal evaluate our operating performance and compare the results of our year, such as “fiscal year 2017,” relate to our fiscal year ended on December 31 operations from period to period without regard to our financing methods or We believe Adjusted EBITDA is useful because it allows us to more effectively 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 2017, 2016 and 2015. of that calendar year. 34 GeoPark 20-F Oil and gas reserves and production information Rounding DeGolyer and MacNaughton 2017 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 totals quantities of proved reserves in Colombia, Chile, Brazil and Peru is derived, in some tables may not be an arithmetic aggregation of the figures that in part, from estimates of the proved reserves as of December 31, 2017. precede them. The reserves estimates described herein are derived from the DeGolyer and MacNaughton Reserves Report (the “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 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 35 Forward-looking Statements This annual report contains statements that constitute forward-looking • the direct or indirect impact on our business resulting from terrorist statements. Many of the forward-looking statements contained in this incidents or responses to such incidents, including the effect on the annual report can be identified by the use of forward-looking words such availability of and premiums on insurance; and as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” • other factors discussed under “Item 3. Key Information—D. Risk factors” in “estimate” and “potential,” among others. this annual report. Forward-looking statements appear in a number of places in this annual Forward-looking statements speak only as of the date they are made, and we report and include, but are not limited to, statements regarding our intent, do not undertake any obligation to update them in light of new information or belief or current expectations. Forward-looking statements are based on future developments or to release publicly any revisions to these statements our management’s beliefs and assumptions and on information currently in order to reflect later events or circumstances or to reflect the occurrence of available to our management. Such statements are subject to risks and unanticipated events. uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors, including, but not limited to, those identified under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties include factors relating to: • the volatility of oil and natural gas prices; • operating risks, including equipment failures and the amounts and timing of revenues and expenses; • termination of, or intervention in, concessions, rights or authorizations granted by the 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, Peru, Argentina 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 acquisitions; • our ability to retain key members of our senior management and key technical employees; • competition from other similar oil and natural gas companies; • market or business conditions and fluctuations in global and local demand for energy; 36 GeoPark 20-F PART I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS A. Directors and senior management 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, 2017 and 2016 and our income statement and cash flow data for the years ended December 31, 2017, 2016 and 2015 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, 2015, 2014, and 2013 and our income statement and cash flow data for the years ended December 31, 2014 and 2013 from our Consolidated Financial Statements not included elsewhere in this annual report. During 2015, our Management changed the presentation of the Consolidated Statement of Income by reordering the profit and loss line items, eliminating gross profit and presenting depreciation and write-off of unsuccessful efforts as separate line items. This change is intended to provide readers of our financial statements with more relevant information and a better explanation of the elements of performance. This change has been applied to comparative figures for the years 2014 and 2013 presented in this document. We maintain our books and records in US$ and prepare our Consolidated Financial Statements in accordance with IFRS. This financial information should be read in conjunction with “Presentation of Financial and Other Information,” “Item 5. Operating and Financial Review and Prospects” and our Consolidated Financial Statements and the related notes thereto. The selected historical financial data set forth in this section does not include any results or other financial information of our Colombian, Brazilian or Peruvian acquisitions prior to their incorporation into our financial statements. GeoPark 37 Statement of income data For the year ended December 31, (in thousands of US$, except per share numbers) 2017 2016 2015 2014 2013 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 61,632 428,734 315,435 22,918 338,353 - - (131,419) (111,296) (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 (5,292) (44,962) (17,252) (69,968) (10,962) – 5,343 83,964 (33,115) (761) 50,088 (15,154) 34,934 12,413 22,521 0.52 0.48 60,093,191 59,777,145 57,759,001 56,396,812 43,603,846 60,093,191 59,777,145 57,759,001 58,840,412 46,532,049 60,596,219 59,940,881 59,535,614 57,790,533 43,861,614 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 for non-financial assets Other operating (expense)/income Operating profit/(loss) Financial costs Foreign exchange loss /gain Profit (Loss) before tax Income tax (expense) benefit (Loss) Profit for the year Non-controlling interest (Loss) Profit attributable to owners of the Company (Losses) Earnings per share for profit attributable to owners of the Company—Basic (Losses) Earnings per share for profit attributable to owners of the Company—Diluted(1) Weighted average common shares outstanding—Basic Weighted average common shares outstanding—Diluted(1) Common Shares outstanding at year-end (1) See Note 19 to our Consolidated Financial Statements. 38 GeoPark 20-F 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 Cash at bank and in hand 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 Total current liabilities Total liabilities 2017 2016 2015 2014 2013 517,403 473,646 522,611 790,767 595,446 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 11,454 5,168 13,358 6,361 571,207 519,339 571,955 838,543 631,787 21,378 5,738 19,519 7,518 26,048 134,755 214,956 786,163 61 239,191 (154,327) 84,925 41,915 126,840 2,480 3,515 18,426 7,402 15,815 73,563 121,201 640,540 60 236,046 (130,341) 105,765 35,828 141,593 418,540 46,284 25,921 2,286 319,389 42,509 34,766 2,770 1,118 4,264 13,480 11,057 19,195 82,730 131,844 703,799 59 232,005 (85,412) 146,652 53,515 200,167 343,248 42,450 19,556 16,955 — 8,532 36,917 13,993 13,459 127,672 200,573 1,039,116 58 210,886 164,613 375,557 103,569 479,126 342,440 46,910 16,583 30,065 — 8,122 42,628 35,764 6,979 121,135 214,628 846,415 44 120,426 150,371 270,841 95,116 365,957 290,457 33,076 8,344 23,087 493,031 399,434 422,209 435,998 354,964 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 26,630 – 7,231 91,633 125,494 480,458 Total equity and liabilities 786,163 640,540 703,799 1,039,116 846,415 GeoPark 39 Cash flow data For the year ended December 31, (In thousands of US$) Cash provided by (used in) Operating activities Investing activities Financing activities Net increase (decrease) in cash Other financial data 2017 2016 2015 2014 2013 142,158 (105,604) 23,968 60,522 82,884 (39,306) (51,136) (7,558) 25,895 (48,842) (18,022) (40,969) 230,746 (344,041) 124,716 11,421 127,295 (208,500) 164,018 82,813 For the year ended December 31, 2017 2016 2015 2014 2013 Adjusted EBITDA(1) (US$ thousands) Adjusted EBITDA margin(2) Adjusted EBITDA per boe(3) 175,776 53.2% 18.4 78,321 40.6% 10.2 73,787 35.2% 10.5 220,077 51.3% 33.0 167,253 49.4% 33.9 (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. 40 GeoPark 20-F Exchange rates In Colombia, Chile, Argentina and Peru, our functional currency is the U.S. Recent exchange rates Period dollar. In Brazil, our functional currency is the real. of Real per US$ Month: Our operations in Brazil accounted for 16% and 12% of our consolidated assets October 2017 and 15% and 10% of our revenues for the years ended December 31, 2016 November 2017 and 2017, respectively. This portion of our business is exposed to losses that December 2017 may arise from currency fluctuation, as a significant amount of our revenues, January 2018 operating costs, administrative expenses and taxes in Brazil are denominated February 2018 in reais. March 2018 April 2018 End Average Low High 3.2769 3.2616 3.3080 3.1624 3.2449 3.3238 3.1912 3.2594 3.2919 3.2106 3.2415 3.2792 3.1315 3.2136 3.2322 3.1391 3.1730 3.2246 3.2801 3.2920 3.3332 3.2697 3.2821 3.3380 The real may depreciate or appreciate substantially against the U.S. dollar. (through April 6, 2018) 3.3666 3.3329 3.3104 3.3666 We recorded exchange rate losses amounting to US$1.3 million for the year ended December 31, 2017, due to devaluation of the local currency in our Source: Central Bank of Brazil. Brazilian subsidiary. This result was mainly generated by the credit facility with Itaú BBA International plc that we incurred on March 31, 2014 to acquire Rio The following table presents the average R$ per U.S. dollar representative das Contas, which we repaid in September 2017. We recorded exchange rate market rate for each of the five most recent years, calculated by using the gains amounting to US$14.5 million for the year ended December 31, 2016 as average of the exchange rates on the last day of each month during the a result of the appreciation that occurred. See “—D. Risk factors—Risks relating period, and the representative year-end market rate for each of the five most to our business—Our results of operations could be materially adversely recent years. affected by fluctuations in foreign currency exchange rates.” The following tables show the selling rate for the U.S. dollar for the periods Period/ and dates indicated. The information in the “Average” column represents Real per US$ Year End Average Low High the average of the daily exchange rates during the periods presented. The Period: numbers in the “Period-end” column are the quotes for the exchange rate as of the last business day of the period in question. As of April 6, 2018, the exchange rate for the purchase of the U.S. dollar as reported by the Central Bank of Brazil was R$3.3666 per U.S. dollar. 2013 2014 2015 2016 2017 The following table presents the monthly high and low representative market First quarter 2018 rate during the months indicated. Second quarter 2018 2.3426 2.6562 3.9048 3.2591 3.3080 3.3238 2.1579 2.3564 3.3876 3.4500 3.2031 3.2437 1.9528 2.1974 2.5690 3.1193 3.0510 3.1391 2.4457 2.7403 4.1949 4.1558 3.3807 3.3380 (through April 6, 2018) 3.3666 3.3329 3.3104 3.3666 Source: Central Bank of Brazil. Exchange rate fluctuation may affect the US$ value of any distributions we make with respect to our common shares. See “—D. Risk factors—Risks relating to our business—Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.” B. Capitalization and indebtedness Not applicable. C. Reasons for the offer and use of proceeds Not applicable. GeoPark 41 Risk factors D. Risk factors Our business, financial condition and results of operations could be • taxes and royalties under relevant laws and the terms of our contracts; materially and adversely affected if any of the risks described below occur. • our ability to enter into oil and natural gas sales contracts at fixed prices; As a result, the market price of our common shares could decline, and you • the level of global methanol demand and inventories and changes in the could lose all or part of your investment. This annual report also contains uses of methanol; forward-looking statements that involve risks and uncertainties. See • the price and availability of alternative fuels; and “Forward-Looking Statements.” The risks below are not the only ones facing • future changes to our hedging policies. our Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. These factors and the volatility of the energy markets make it extremely 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, 2013 to December 31, 2017, Brent spot prices ranged from A substantial or extended decline in oil, natural gas and methanol prices a low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub may materially adversely affect our business, financial condition or results natural gas average spot prices ranged from a low of US$1.7 per mmbtu to of operations. a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$250.0 per metric ton to a high of US$635.1 per metric The prices that we receive for our oil and natural gas production heavily ton. Furthermore, oil, natural gas and methanol prices do not necessarily influence our revenues, profitability, access to capital and growth rate. fluctuate in direct relationship to each other. Historically, the markets for oil, natural gas and methanol (which have For the year ended December 31, 2017, 85% of our revenues were derived influenced prices for almost all of our Chilean gas sales) have been volatile and from oil. Because we expect that our production mix will continue to be will likely continue to be volatile in the future. International oil, natural gas and weighted towards oil, our financial results are more sensitive to movements methanol prices have fluctuated widely in recent years and may continue to in oil prices. do so in the future. As of December 31, 2017, natural gas comprised 15% of our revenues. A decline in natural gas prices could negatively affect our future growth, The prices that we will receive for our production and the levels of our particularly for future gas sales where we may not be able to secure or production depend on numerous factors beyond our control. These factors extend our current long-term contracts. include, but are not limited, to the following: Lower oil and natural gas prices may impact our revenues on a per unit • global economic conditions; basis, and may also reduce the amount of oil and natural gas that can be produced economically. In addition, changes in oil and natural gas • changes in global supply and demand for oil, natural gas and methanol; prices can impact the valuation of our reserves and, in periods of lower • the actions of the Organization of the Petroleum Exporting Countries commodity prices, we may curtail production and capital spending or may (“OPEC”); defer or delay drilling wells because of lower cash generation. Lower oil • political and economic conditions, including embargoes, in oil-producing and natural gas prices could also affect our growth, including future and countries or affecting other countries; pending acquisitions. A substantial or extended decline in oil or natural gas • the level of oil- and natural gas-producing activities, particularly in the prices could adversely affect our business, financial condition and results of Middle East, Africa, Russia, South America and the United States; operations. • the level of global oil and natural gas exploration and production activity; For example, during 2014 and 2015, we evaluated the recoverability of our • the level of global oil and natural gas inventories; fixed assets affected by the oil price decline and recorded an impairment of • the price of methanol; • availability of markets for natural gas; non-financial assets amounting to, respectively, US$9.4 million and US$149.6 million. US$5.7 million of the impairment recorded in 2015 was reversed • weather conditions and other natural disasters; in 2016 due to increased estimated market prices for 2017 and 2018 and • technological advances affecting energy production or consumption; improvements in cost structure. After conducting an impairment test • domestic and foreign governmental laws and regulations, including procedure for the year ended December 31, 2017, no additional impairment environmental, health and safety laws and regulations; of non-financial assets was recognized. See Note 36 to our Consolidated • proximity and capacity of oil and natural gas pipelines and other Financial Statements for details regarding oil price scenarios, discount rates transportation facilities; considered and sensitivity analysis affecting the impairment charges. • the price and availability of competitors’ supplies of oil and natural gas in Continuing our hedging strategy, we entered into derivative financial captive market areas; instruments to manage exposure to oil price risk. These derivatives were • quality discounts for oil production based, among other things, on API and zero-premium collars or zero premium three way hedges (put, spread and mercury content; 42 GeoPark 20-F call) and were placed with major financial institutions and commodity traders. We entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provide credit lines for collateral the incurrence of additional indebtedness, including additional bank posting thus alleviating possible liquidity needs under the instruments and credit facilities, equity issuances or the sale of minority stakes in certain protecting us from potential non-performance risk by our counterparties. operations to our partners. We may need to raise additional funds more See Note 8 to our Consolidated Financial Statements for details regarding quickly if one or more of our assumptions prove to be incorrect or if we Commodity Risk Management Contracts. choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and The oil price crisis has impacted our operations and corporate strategy. we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. The ultimate amount of capital We face limitations on our ability to increase prices or improve margins that we will expend may fluctuate materially based on market conditions, on the oil and natural gas that we sell. As a consequence of the oil price our continued production, decisions by the operators in blocks where crisis which started in the second half of 2014 (WTI and Brent, the main we are not the operator, the success of our drilling results and future international oil price markers, fell by more than 60% between August 2014 acquisitions. Our future financial condition and liquidity will be impacted and March 2016), the Company took decisive measures to ensure its ability by, among other factors, our level of production of oil and natural gas and to both maximize ongoing projects and to preserve its cash. the prices we receive from the sale thereof, the success of our exploration Funding our anticipated capital expenditures relies in part on oil prices and appraisal drilling program, the number of commercially viable oil remaining close to our estimates or higher levels and other factors to and natural gas discoveries made and the quantities of oil and natural generate sufficient cash flow. Low oil prices affect our revenues, which gas discovered, the speed with which we can bring such discoveries to in turn affect our debt capacity and the covenants in our financing production and the actual cost of exploration, appraisal and development agreements, as well as the amount of cash we can borrow using our oil of our oil and natural gas assets. reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment Unless we replace our oil and natural gas reserves, our reserves and agreements. If we are not able to generate the sales which, together with production will decline over time. Our business is dependent on our our current cash resources, are sufficient to fund our capital program, we continued successful identification of productive fields and prospects and will not be able to efficiently execute our work program, which would cause the identified locations in which we drill in the future may not yield oil or us to further decrease our work program and would harm our business natural gas in commercial quantities. outlook, investor confidence and our share price. In addition, actions taken by the company to maximize ongoing projects Production from oil and gas properties declines as reserves are depleted, and to reduce expenses, including renegotiations and reduction of oil with the rate of decline depending on reservoir characteristics. Accordingly, and gas service contracts and other initiatives such as cost cutting may our current proved reserves will decline as these reserves are produced. As of expose us to claims and contingencies from interested parties that may December 31, 2017, our reserves-to-production (or reserve life) ratio for net have a negative impact on our business, financial condition, results of proved reserves in Colombia, Chile, Brazil and Peru was 9.5 years. According operations and cash flows. If oil prices are lower than expected, we may be to estimates, if on January 1, 2018 we ceased all drilling and development unable to meet our contractual obligations with oil and service contracts activities, including recompletions, refracs and workovers, our proved and our suppliers. Equally, those third parties may be unable to meet their developed producing reserves base in Colombia, Chile, Brazil and Peru contractual obligations to us as a result of the oil price crisis, impacting on would decline 35% during the first year. our operations. In budgeting for our future activities, we have relied on a number of Our future oil and natural gas reserves and production, and therefore our assumptions, including, with regard to our discovery success rate, the cash flows and income, are highly dependent on our success in efficiently number of wells we plan to drill, our working interests in our prospects, developing our current reserves and using cost-effective methods to find the costs involved in developing or participating in the development of a or acquire additional recoverable reserves. While we have had success in prospect, the timing of third-party projects and our ability to obtain needed identifying and developing commercially exploitable fields and drilling financing with respect to any further acquisitions and the availability of locations in the past, we may be unable to replicate that success in the both suitable equipment and qualified personnel. These assumptions are future. We may not identify any more commercially exploitable fields or inherently subject to significant business, political, economic, regulatory, successfully drill, complete or produce more oil or gas reserves, and the environmental and competitive uncertainties, conditions in the financial wells which we have drilled and currently plan to drill within our blocks or markets, contingencies and risks, all of which are difficult to predict and concession areas may not discover or produce any further oil or gas or may many of which are beyond our control. In addition, we opportunistically not discover or produce additional commercially viable quantities of oil or seek out new assets and acquisition targets to complement our existing gas to enable us to continue to operate profitably. If we are unable to replace operations, and have financed such acquisitions in the past through our current and future production, the value of our reserves will decrease, GeoPark 43 and our business, financial condition and results of operations will be fluctuations in foreign currency exchange rates. materially adversely affected. We derive a significant portion of our revenues from sales to a few key fluctuations in foreign currency exchange rates for certain of our expenses in Although a majority of our net revenues is denominated in US$, unfavorable customers. Colombia, Chile, Brazil, Peru and Argentina could have a material adverse effect on our results of operations. A portion of the cost reductions that we achieved In Colombia, for the year ended December 31, 2017, we made 100% of our in 2015 and 2016 (as compared to 2014) were related to the depreciation of oil sales from operated blocks to C.I. Trafigura Petroleum Colombia S.A.S., a local currencies, including mainly the Col$, the Ch$ and the Brazilian real. An leading commodity trading and logistics company (“Trafigura”), representing appreciation of local currencies can increase our costs and negatively impact 79% of our consolidated revenues for the same period. Sales for the year ended our results from operations. December 31, 2017 were made mostly under long-term agreements. For 2018, all of the oil production from the blocks we operate in Colombia is committed Furthermore, we have not entered, into derivative transactions to hedge the to Trafigura under the Trafigura Sales Agreement. effect of changes in the exchange rate of local currencies to the US$. Because our Consolidated Financial Statements are presented in US$, we must translate In Chile, 100% of our crude oil and condensate sales are made to ENAP. For revenues, expenses and income, as well as assets and liabilities, into US$ at the year ended December 31, 2017, sales to ENAP represented 5% of our exchange rates in effect during or at the end of each reporting period. total revenues. ENAP imports the majority of the oil it refines and partially supplements those imports with volumes supplied locally by its own operated Through our Brazilian operations, we are exposed to fluctuations in the fields and those operated by us. On April 21, 2017, we renewed our sales real against the US$, as our Brazilian revenues and expenses are mostly agreement with ENAP. As part of this agreement, ENAP has committed to denominated in reais. In the past, the Brazilian Central Bank has occasionally purchase our oil production in the Fell Block in the amounts that we produce, intervened to control unstable movements in foreign exchange rates. We subject to the limitation of available storage capacity at the Gregorio Terminal. cannot predict whether the Brazilian Central Bank or the Brazilian government The sales agreement provides us with the option to interrupt sales to ENAP will continue to permit the real to float freely or will intervene in the exchange periodically if conditions in the export markets allow for more competitive rate market through the return of a currency band system or otherwise. price levels. While the agreement renews automatically on an annual basis, Furthermore, Brazilian law provides that, whenever there is a serious imbalance we typically make an annual revision jointly with ENAP. In addition, for the in Brazil’s balance of payments or there are reasons to foresee a serious year ended December 31, 2017, almost all of our natural gas sales in Chile imbalance, temporary restrictions may be imposed on remittances of foreign were made to Methanex Chile SpA., the Chilean subsidiary of the Methanex capital abroad. We cannot assure you that such measures will not be taken by Corporation (“Methanex”), a leading global methanol producer, under a the Brazilian government in the future. The real has experienced frequent and long-term contract (the “Methanex Gas Supply Agreement”) which expired on substantial variations in relation to the US$ and other foreign currencies, which April 30, 2017. In March 2017, we executed a new gas supply agreement with could materially and adversely affect the growth of the Brazilian economy and Methanex effective from May 1, 2017 to December 31, 2026. Sales to Methanex our business, financial condition and results of operations. represented 5% of our consolidated revenues for the year ended December 31, 2017. There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas. In Brazil, all of our gas and condensate produced in the Manati Field is sold to Petróleo Brasileiro S.A. (“Petrobras”), the operator of the Manati Field, Our performance depends on the success of our exploration and pursuant to a long-term gas off-take contract. See “Item 4. Information on the production activities and on the existence of the infrastructure that will Company—B. Business Overview—Significant Agreements—Brazil—Petrobras allow us to take advantage of our oil and gas reserves. Oil and natural Natural Gas Purchase Agreement.” gas exploration and production activities are subject to numerous risks beyond our control, including the risk that exploration activities will not If any of our buyers were to decrease or cease purchasing oil or gas from us, identify commercially viable quantities of oil or natural gas. Our decisions or if any of them were to decide not to renew their contracts with us or to to purchase, explore, develop or otherwise exploit prospects or properties renew them at a lower sales price, this could have a material adverse effect on will depend in part on the evaluation of seismic and other data obtained our business, financial condition and results of operations. For example, see through geophysical, geochemical and geological analysis, production “Item 4. Information on the Company—B. Business Overview—Significant data and engineering studies, the results of which are often inconclusive or Agreements—Colombia” and “Item 4. Information on the Company—B. subject to varying interpretations. Business Overview—Significant Agreements—Chile.” Our results of operations could be materially adversely affected by our projects may be affected by numerous factors beyond our control. Furthermore, the marketability of any oil and natural gas production from 44 GeoPark 20-F These factors include, but are not limited to, proximity and capacity of make substantial capital expenditures in our business and operations for pipelines and other means of transportation, the availability of upgrading the exploration and production of oil and natural gas reserves. See “Item 4. and processing facilities, equipment availability and government laws and Information on the Company –B. Business Overview—2018 Strategy and regulations (including, without limitation, laws and regulations relating to Outlook.” We incurred capital expenditures of US$106 million and US$39 prices, sale restrictions, taxes, governmental stake, allowable production, million during the years ended December 31, 2017 and 2016, respectively. importing and exporting of oil and natural gas, environmental protection See “Item 5. Operating and Financial Review and Prospects—A. Operating and health and safety). The effect of these factors, individually or jointly, Results—Factors Affecting our Results of Operations—Discovery and cannot be accurately predicted, but may have a material adverse effect on exploitation of reserves.” our business, financial condition and results of operations. The actual amount and timing of our future capital expenditures may differ There can be no assurance that our drilling programs will produce oil materially from our estimates as a result of, among other things, commodity and natural gas in the quantities or at the costs anticipated, or that our prices, actual drilling results, the availability of drilling rigs and other currently producing projects will not cease production, in part or entirely. equipment and services, and regulatory, technological and competitive Drilling programs may become uneconomic as a result of an increase in developments. In response to changes in commodity prices, we may increase our operating costs or as a result of a decrease in market prices for oil and or decrease our actual capital expenditures. We intend to finance our future natural gas. Our actual operating costs or the actual prices we may receive capital expenditures through cash generated by our operations and potential for our oil and natural gas production may differ materially from current future financing arrangements. However, our financing needs may require estimates. In addition, even if we are able to continue to produce oil and us to alter or increase our capitalization substantially through the issuance of gas, there can be no assurance that we will have the ability to market our oil debt or equity securities or the sale of assets. and gas production. See “—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas If our capital requirements vary materially from our current plans, we may markets and generate significant incremental costs or delays in our oil and require further financing. In addition, we may incur significant financial natural gas production” below. indebtedness in the future, which may involve restrictions on other financing and operating activities. We may also be unable to obtain financing or Our identified potential drilling location inventories are scheduled over financing on terms favorable to us. These changes could cause our cost many years, making them susceptible to uncertainties that could materially of doing business to increase, limit our ability to pursue acquisition alter the occurrence or timing of their drilling. opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the Our management team has specifically identified and scheduled certain availability of credit could materially adversely affect our ability to achieve our potential drilling locations as an estimation of our future multi-year drilling planned growth and operating results. activities on our existing acreage. These identified potential drilling locations, including those without proved undeveloped reserves, represent a significant Oil and gas operations contain a high degree of risk and we may not be fully part of our growth strategy. insured against all risks we face in our business. Our ability to drill and develop these identified potential drilling locations Oil and gas exploration and production is speculative and involves a high depends on a number of factors, including oil and natural gas prices, the degree of risk and hazards. In particular, our operations may be disrupted availability and cost of capital, drilling and production costs, the availability by risks and hazards that are beyond our control and that are common of drilling services and equipment, drilling results, lease expirations, the among oil and gas companies, including environmental hazards, blowouts, availability of gathering systems, marketing and transportation constraints, industrial accidents, occupational safety and health hazards, technical refining capacity, regulatory approvals and other factors. Because of the failures, labor disputes, community protests or blockades, unusual or uncertainty inherent in these factors, there can be no assurance that the unexpected geological formations, flooding, earthquakes and extended numerous potential drilling locations we have identified will ever be drilled or, interruptions due to weather conditions, explosions and other accidents. if they are, that we will be able to produce oil or natural gas from these or any other potential drilling locations. While we believe that we maintain customary insurance coverage for companies engaged in similar operations, we are not fully insured against Our business requires significant capital investment and maintenance all risks in our business. In addition, insurance that we do and plan to carry expenses, which we may be unable to finance on satisfactory terms or at all. may contain significant exclusions from and limitations on coverage. We Because the oil and natural gas industry is capital intensive, we expect to believe that the cost of available insurance is excessive relative to the risks may elect not to obtain certain non-mandatory types of insurance if we GeoPark 45 presented. The occurrence of a significant event or a series of events against be expensive to develop, purchase and implement and may not function which we are not fully insured and any losses or liabilities arising from as expected. Such uncertainties and operating risks associated with uninsured or underinsured events could have a material adverse effect on development projects could have a material adverse effect on our business, our business, financial condition or results of operations. results of operations or financial condition. The development schedule of oil and natural gas projects is subject to cost Competition in the oil and natural gas industry is intense, which makes it overruns and delays. difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel. Oil and natural gas projects may experience capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling We compete with the major oil and gas companies engaged in the exploration rigs and other essential equipment, supplies, personnel and oil field services. and production sector, including state-owned exploration and production The cost to execute projects may not be properly established and remains companies that possess substantially greater financial and other resources dependent upon a number of factors, including the completion of detailed than we do for researching and developing exploration and production cost estimates and final engineering, contracting and procurement costs. technologies and access to markets, equipment, labor and capital required Development of projects may be materially adversely affected by one or more to acquire, develop and operate our properties. We also compete for the of the following factors: • shortages of equipment, materials and labor; acquisition of licenses and properties in the countries in which we operate. • fluctuations in the prices of construction materials; Our competitors may be able to pay more for productive oil and natural • delays in delivery of equipment and materials; gas properties and exploratory prospects and to evaluate, bid for and • labor disputes; • political events; • title problems; • obtaining easements and rights of way; • blockades or embargoes; • litigation; purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. As a result of each of the aforementioned, we may not be able to compete successfully in the future in • compliance with governmental laws and regulations, including acquiring prospective reserves, developing reserves, marketing hydrocarbons, environmental, health and safety laws and regulations; attracting and retaining quality personnel or raising additional capital, which • adverse weather conditions; • unanticipated increases in costs; • natural disasters; • accidents; • transportation; could have a material adverse effect on our business, financial condition or results of operations. See “Item 4. Information on the Company—B. Business Overview—Our competition.” Our estimated oil and gas reserves are based on assumptions that may • unforeseen engineering and drilling complications; prove inaccurate. • environmental or geological uncertainties; and • other unforeseen circumstances. Our oil and gas reserves estimates in Colombia, Chile, Brazil, and Peru as of December 31, 2017 are based on the D&M Reserves Report. Although Any of these events or other unanticipated events could give rise to delays in classified as “proved reserves,” the reserves estimates set forth in the D&M development and completion of our projects and cost overruns. Reserves Reports are based on certain assumptions that may prove inaccurate. For example, in 2017, the drilling and completion cost for the exploratory well included oil and gas sales prices determined according to SEC guidelines, Río Grande Oeste x-1 in our CN-V Block in Argentina was originally estimated future expenditures and other economic assumptions (including interests, at US$4.2 million, but the actual cost was US$5.5 million, mainly due to 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 DeGolyer and MacNaughton’s primary economic assumptions in estimates 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 oil and gas, many of which are beyond our control. Results of drilling, testing accumulations of oil and gas that cannot be measured in an exact way, 46 GeoPark 20-F and production after the date of the estimate may require revisions to be produce in Chile. We rely upon the continued good condition, maintenance made. For example, if we are unable to sell our oil and gas to customers, this and accessibility of the roads we use to deliver the crude oil we produce. If may impact the estimate of our oil and gas reserves. Accordingly, reserves the condition of these roads were to deteriorate or if they were to become estimates are often materially different from the quantities of oil and gas that inaccessible for any period of time, this could delay delivery of crude oil in Chile are ultimately recovered, and if such recovered quantities are substantially and materially harm our business. lower than the initial reserves estimates, this could have a material adverse impact on our business, financial condition and results of operations. In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas we produce to Methanex, the sole purchaser of the gas we produce. If ENAP’s Our inability to access needed equipment and infrastructure in a timely pipelines were unavailable, this could have a materially adverse effect on our manner may hinder our access to oil and natural gas markets and generate ability to deliver and sell our product to Methanex, which could have a material significant incremental costs or delays in our oil and natural gas production. adverse effect on our gas sales. In addition, gas production in some areas in the Tierra del Fuego Blocks and the Tranquilo Block could require us to build a Our ability to market our oil and natural gas production depends substantially new network of gas pipelines in order for us to be able to deliver our product to on the availability and capacity of processing facilities, oil tankers, market, which could require us to make significant capital investments. transportation facilities (such as pipelines, crude oil unloading stations and trucks) and other necessary infrastructure, which may be owned and operated While Brazil has a well-developed network of hydrocarbon pipelines, storage by third parties. Our failure to obtain such facilities on acceptable terms or and loading facilities, we may not be able to access these facilities when on a timely basis could materially harm our business. We may be required to needed. Pipeline facilities in Brazil are often full and seasonal capacity shut down oil and gas wells because access to transportation or processing restrictions may occur, particularly in natural gas pipelines. Our failure to secure facilities may be limited or unavailable when needed. If that were to occur, then transportation or access to pipelines or other facilities once we commence we would be unable to realize revenue from those wells until arrangements operations in the concessions we were awarded in Brazil on acceptable terms were made to deliver the production to market, which could cause a material or on a timely basis could materially harm our business. adverse effect on our business, financial condition and results of operations. In addition, the shutting down of wells can lead to mechanical problems In Peru, future production in the Morona Block is expected to be transported upon bringing the production back on line, potentially resulting in decreased through the existing North Peruvian Pipeline, which was out of service in 2017 production and increased remediation costs. The exploitation and sale of oil due to technical issues. Though the Peruvian government is implementing and natural gas and liquids will also be subject to timely commercial processing a program to maintain the pipeline, future technical issues, other general and marketing of these products, which depends on the contracting, financing, infrastructure problems or social unrest affecting pipeline operation may building and operating of infrastructure by third parties. adversely affect the recoverability of our future investments, our future production or revenues related to the Morona Block. In Colombia, producers of crude oil have historically suffered from tanker transportation logistics issues and limited storage capacity, which cause delays In addition, as the Morona Block is located in a remote area of the tropical in delivery and transfer of title of crude oil. Such capacity issues in Colombia rainforest, the development of the project involves that significant may require us to transport crude from our Colombian operations via truck, infrastructure has to be built, as processing facilities, storages tanks and an which may increase the costs of those operations. Road infrastructure is limited approximately 97 km pipeline from the site to the North Peruvian Pipeline. in certain areas in which we operate, and certain communities have used and Also, as there are no roads available in the surrounding area, logistics will be may continue to use road blockages, which can sometimes interfere with our performed by helicopters or barges during specific seasons of the year. These operations in these areas. For example, in 2017, the main delivery point for the issues may lead us to incur significant costs or investments that may not be Colombian production was Oleoducto de Los Llanos “ODL.” Between November recoverable through our commercial activities in the Morona Block.  8, 2017 and November 11, 2017, a disruption of the operation of this pipeline occurred and affected its capacity to transport any volume of crude oil. Our Our use of seismic data is subject to interpretation and may not accurately Colombian production was impacted by approximately 5,800 bbls during that identify the presence of oil and natural gas. period. Although we were able to increase the delivery volumes the following days to mitigate the impact, we cannot assure you we would be able to do so Even when properly used and interpreted, seismic data and visualization in the future. techniques are tools only used to assist geoscientists in identifying subsurface structures as well as eventual hydrocarbon indicators, and do not enable In Chile, we transport the crude oil we produce in the Fell Block by truck to the interpreter to know whether hydrocarbons are, in fact, present in those ENAP’s processing, storage and selling facilities at the Gregorio Refinery. structures. In addition, the use of seismic and other advanced technologies As of the date of this annual report, ENAP purchases all of the crude oil we requires significant expenditures and we could incur losses as a result of GeoPark 47 these expenditures. Because of these uncertainties associated with our We may suffer delays or incremental costs due to difficulties in negotiations use of seismic data, some of our drilling activities may not be successful with landowners and local communities, including native communities, or economically viable, and our overall drilling success rate or our drilling where our reserves are located. success rate for activities in a particular area could decline, which could have a material adverse effect on us. Access to the sites where we operate requires agreements (including, for example, assessments, rights of way and access authorizations) with Through our Brazilian operations, we face operational risks relating to landowners and local communities. If we are unable to negotiate agreements offshore drilling. 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. Our operations in the BCAM-40 Concession in Brazil may include shallow- In Chile and in Argentina, for example, we have negotiated the necessary offshore drilling activity in two areas in the Camamu-Almada Basin, which we agreements for many of our current operations in the Magallanes Basin and expect will continue to be operated by Petrobras. CN-V Block in Mendoza, respectively. In Brazil, in the event that social unrest Offshore operations are subject to a variety of operating risks and laws and ability to operate the assets we have acquired or may acquire in our Brazil continues or intensifies, this may lead to delays or damage relating to our regulations, including among other things, with respect to environmental, Acquisitions. health and safety matters, specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse In Colombia, although we have agreements with many landowners and are weather conditions. These conditions can cause substantial damage to in negotiations with others, we expect our costs to increase following current facilities and interrupt production. As a result, we could incur substantial and future negotiations regarding access to our blocks, as the economic liabilities, compliance costs, fines or penalties that could reduce or eliminate expectations of landowners have generally increased, which may delay the funds available for exploration, development or leasehold acquisitions, or access to existing or future sites. In addition, the expectations and demands result in loss of equipment and properties. For example, the Manati Field has of local communities on oil and gas companies operating in Colombia may been subject to administrative infraction notices, which have resulted in fines also increase. As a result, local communities have demanded that oil and against Petrobras in an aggregate amount of approximately US$12 million, gas companies invest in remediating and improving public access roads, all of which are pending a final decision of the Brazilian Institute for the compensate them for any damages related to use of such roads and, more Environment and Natural Renewable Resources (Instituto Brasileiro do Meio- generally, invest in infrastructure that was previously paid for with public Ambiente e dos Recursos Naturais Renováveis). Although the administrative funds. Due to these circumstances, oil and gas companies in Colombia, fines were filed against Petrobras, as a party to the concession agreement including us, are now dealing with increasing difficulties resulting from governing the Manati Field, we may be liable up to our participation interest instances of social unrest, temporary road blockages and conflicts with of 10%. landowners. Additionally, offshore drilling generally requires more time and more There can be no assurance that disputes with landowners and local advanced drilling technologies, involving a higher-risk of technological communities will not delay our operations or that any agreements we reach failure and usually higher drilling costs. Offshore projects often lack proximity with such landowners and local communities in the future will not require us to existing oilfield service infrastructure, necessitating significant capital to incur additional costs, thereby materially adversely affecting our business, investment in flow line infrastructure before we can market the associated oil financial condition and results of operations. Local communities may also or gas of a commercial discovery, increasing both the financial and operational protest or take actions that restrict or cause their elected government to risk involved with these operations. Because of the lack and high cost of restrict our access to the sites of our operations, which may have a material infrastructure, some offshore reserve discoveries may never be produced adverse effect on our operations at such sites. economically. Further, because we are not the operator of our offshore fields, all of these Though we have already signed certain agreements with native communities risks may be heightened since they are outside of our control. We have a authorizing the execution of the Environmental Impact Assessment for 10% interest in the Manati Field which limits our operating flexibility in such the Morona Project, similar projects in the Peruvian rainforest have faced offshore fields. See “—We are not, and may not be in the future, the sole owner significant social conflicts and work delays due to community claims. Social or operator of all of our licensed areas and do not, and may not in the future, conflicts or community claims could adversely affect the recoverability of our hold all of the working interests in certain of our licensed areas. Therefore, we future investments, our future production and revenues related to the Morona In Peru, the Morona Block is located in land inhabited by native communities. may not be able to control the timing of exploration or development efforts, Block. associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly-owned, assets.” 48 GeoPark 20-F 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 and the Morona establish development areas. Failure to meet these obligations may result in Block in Peru. the loss of our interests in the undeveloped parts of our blocks or concession areas. For the year ended December 31, 2017, the Llanos 34 Block contained 66% of our net proved reserves and generated 75% of our production, the Fell Block In order to protect our exploration and production rights in our license areas, contained 8% of our net proved reserves and generated 10% of our total we must meet various drilling and declaration requirements. In general, unless production, the BCAM-40 Concession contained 4% of our net proved reserves we make and declare discoveries within certain time periods specified in our and generated 11% of our production and the Morona Block contained 20% of various special operation contracts (Contratos Especiales de Operación para our net proved reserves. While our continuing expansion with new exploratory la Exploración y Explotación de Yacimientos de Hidrocarburo; hereinafter blocks incorporated in our portfolio mean that the above mentioned blocks “CEOP”), E&P Contracts and concession agreements, our interests in the may be expected to be a less significant component of our overall business, undeveloped parts of our license areas may lapse. Should the prospects we we cannot be sure that we will be able to continue diversifying our reserves have identified under these contracts and agreements yield discoveries, and production. Resulting from these, any government intervention, we may face delays in drilling these prospects or be required to relinquish impairment or disruption of our production due to factors outside of our these prospects. The costs to maintain or operate the CEOPs, E&P Contracts control or any other material adverse event in our operations in such blocks and concession agreements over such areas may fluctuate and may increase would have a material adverse effect on our business, financial condition and significantly, and we may not be able to meet our commitments under such results of operations. contracts and agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. For example, in 2016, after Our contracts in obtaining rights to explore and develop oil and natural fulfilling the committed exploratory commitments, five exploratory blocks gas reserves are subject to contractual expiration dates and operating were relinquished to the ANP. See “Item 4. Information on the Company—B. conditions, and our CEOPs, E&P Contracts and concession agreements are Business Overview—Our operations—Operations in Brazil.” subject to early termination in certain circumstances. In Peru, the rights to explore and produce hydrocarbons are granted through Under certain CEOPs, E&P Contracts and concession agreements to which a license contract signed with Perupetro. The scope and schedule of such we are or may in the future become parties, we are or may become subject development will depend on us and Petroperu. The license contract could to guarantees to perform our commitments and/or to make payment for be terminated by Perupetro if the development obligations included in other obligations, and we may not be able to obtain financing for all such such agreement are not fulfilled. In addition, there is also an exploratory obligations as they arise. If such obligations are not complied with when commitment consisting of the drilling of one exploratory well every two and due, in addition to any other remedies that may be available to other parties, a half years. Failure to fulfill the exploratory commitment will lead to acreage this could result in cancelation of our CEOPs, E&P Contracts and concession relinquishment materially affecting the project. Moreover, we have entered agreements or dilution or forfeiture of interests held by us. As of December into a Joint Investment Agreement with Petroperu by which, subject to the 31, 2017, the aggregate outstanding amount of this potential liability for economic and technical feasibility of the Morona Project, we are obliged guarantees was US$28.4 million, mainly related to capital commitments in to bear 100% of capital cost required to carry out long test to existing well Isla Norte, Campanario and Flamenco Blocks in Chile, rounds 11, 12 and 13 Situche Central 3X, and if we decide to continue with the project after concessions in Brazil, the Morona Block in Peru and the Llanos 32, VIM-3, and that, to the existing well Situche Central 2X. In addition, we are required to Llanos 34 Blocks in Colombia. See “Item 4. Information on the Company—B. cover any capital or operational expenditures associated with the project Business Overview—Our operations” and Note 32(b) to our Consolidated until December 31, 2020. We expect these expenditures to be substantially Financial Statements. reimbursed by Petroperu from revenues associated with future sales. Failure to fulfill such obligations will result in the loss of our participating interest in Additionally, certain of the CEOPs, E&P Contracts and concession agreements the License Contract of the Morona Block, and subject us to possible damage to which we are or may in the future become a party are subject to set claims from Petroperu. expiration dates. Although we may want to extend some of these contracts beyond their original expiration dates, there is no assurance that we can do For additional details regarding the status of our operations with respect so on terms that are acceptable to us or at all, although some CEOPs contain to our various special contracts and concession agreements, see “Item 4. provisions enabling exploration extensions. Information on the Company—B. Business Overview—Our operations.” In Colombia, our E&P Contracts may be subject to early termination for a GeoPark 49 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 approval of environmental impact assessment (EIA) interfere with our abandonment obligations and excluding certain pipelines study for project development. The expiration of the License Contract will and other assets. See “Item 4. Information on the Company—B. Business occur twenty years after EIA approval. The License Contract is also subject Overview—Significant Agreements—Chile—CEOPs—Fell Block CEOP.” If the to early termination in case of our breach of contractual obligations. In CEOP is terminated early due to a breach of our obligations, we may not be such an event, all the existing facilities and wells located in the block will entitled to compensation. Our CEOPs for the Tierra del Fuego Blocks, which be transferred, without charge, to Perupetro, and we will have to carry out are in the exploration phase, may be subject to early termination during this abandonment plans for remediation and restoration of any polluted area in phase under certain circumstances, including if we fail to perform under the block and for de-commission the facilities that are no longer required for the terms of the CEOPs, voluntarily relinquish all areas under the CEOPs or 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 Early termination or nonrenewal of any CEOP, E&P Contract or concession are released from all obligations under the CEOPs, except for obligations agreement could have a material adverse effect on our business, financial regarding the abandonment of fields, if any. See “Item 4. Information on the situation or results of operations. Company—B. Business Overview—Significant Agreements—Chile—CEOPs.” There can be no assurance that the early termination of any of our CEOPs We may not be able to meet delivery requirements under the crude sale would not have a material adverse effect on us. In addition, according to agreements in Colombia. the Chilean Constitution, Chile is entitled to expropriate our rights in our CEOPs for reasons of public interest. Although Chile would be required to We historically sold to several customers in Colombia, including sales made indemnify us for such expropriation, there can be no assurance that any such through wellhead or pipeline. For 2018, we expect to sell almost all of our indemnification will be paid in a timely manner or in an amount sufficient to Colombian production under long-term agreements with Trafigura. The cover the harm to our business caused by such expropriation. Trafigura offtake contract began in March 2016 and expires in December 2018. In Brazil, concession agreements in the production phase generally may be The amended Trafigura Agreement sets the current volumes to be delivered renewed at the ANP’s discretion for an additional period, provided that a to Trafigura to 12,000 bopd until December 2018. Nonperformance of our renewal request is made at least 12 months prior to the termination of the obligations of delivery to Trafigura in terms, amounts and quality of the crude concession agreement and there has not been a breach of the terms of the may lead us to pay ship-or-pay commitments in the ODL Pipeline for the concession agreement. We expect that all our concession agreements will transport, dilution and download of crude as well as compensation for other provide for early termination in the event of: (i) government expropriation costs. Additionally, such nonperformance may lead to early termination of the for reasons of public interest; (ii) revocation of the concession pursuant to the crude sales agreement as well as the immediate repayment of any amounts terms of the concession agreement; or (iii) failure by us or our partners to fulfill outstanding under the prepayment agreement of up to US$100 million, all of our respective obligations under the concession agreement (subject to a as well as compensation for other damages. As of December 31, 2017, the cure period). Administrative or monetary sanctions may also be applicable, as outstanding balance was US$10 million, relating to the amount we agreed to determined by the ANP, which shall be imposed based on applicable law and prepay Trafigura. regulations. In the event of early termination of a concession agreement, the compensation to which we are entitled may not be sufficient to compensate We sell almost all of our natural gas in Chile to a single customer, who has in the past temporarily idled its principal facility. 50 GeoPark 20-F For the year ended December 31, 2017, almost all of our natural gas sales Company—B. Business Overview—Operations in Colombia, Operations in in Chile were made to Methanex under a long-term contract, the Methanex Chile, Operations in Brazil, Operations in Peru and Operations in Argentina.” Gas Supply Agreement, which expires on December 31, 2026. Under the agreement, Methanex committed to purchase up to 400,000 SCM/d of gas In addition, the terms of the joint venture agreements or association produced by us. For 2018, the commitment was reduced to 315,000 SCM/d, agreements governing our other partners’ interests in almost all of the blocks due to the decline in the gas production. We also hold an option to deliver that are not wholly-owned or operated by us require that certain actions be up to 15% above this volume. Sales to Methanex represented approximately approved by supermajority vote. The terms of our other current or future 5% of our consolidated revenues for the year ended December 31, 2017. license or venture agreements may require at least the majority of working Methanex also buys gas from ENAP and a consortium that Methanex has interests to approve certain actions. As a result, we may have limited ability to formed with ENAP. If Methanex were to decrease or cease its purchase of gas exercise influence over operations or prospects in the blocks operated by our from us, this would have a material adverse effect on our revenues derived partners, or in blocks that are not wholly-owned or operated by us. A breach of from the sale of gas. contractual obligations by our partners who are the operators of such blocks could eventually affect our rights in exploration and production contracts in Methanex has two methanol producing facilities at its Cabo Negro some of our blocks in Colombia and Brazil. Our dependence on our partners production facility, near the city of Punta Arenas in southern Chile. Methanex could prevent us from realizing our target returns for those discoveries or relies on local suppliers of natural gas, including ENAP, for its operations. prospects. We alone cannot supply Methanex with all the natural gas it requires for its operations. 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 LGI, our strategic partner in Chile and Colombia, may not consent to our could have a material adverse effect on our business, financial condition and taking certain actions or may eventually decide to sell its interest in our results of operations. Chilean and Colombian operations to a third party. We are not, and may not be in the future, the sole owner or operator of all We have a strategic partnership with LGI, which has a 20% equity interest of our licensed areas and do not, and may not in the future, hold all of the in GeoPark Chile S.A., (a sociedad anónima cerrada incorporated under working interests in certain of our licensed areas. Therefore, we may not be the laws of Chile; hereinafter “GeoPark Chile”), a 14% direct equity interest able to control the timing of exploration or development efforts, associated in GeoPark TdF S.A. (“GeoPark TdF”) (31.2% taking into account direct costs, or the rate of production of any non-operated and, to an extent, any and indirect participation through GeoPark Chile) and a 20% equity non-wholly-owned, assets. interest in GeoPark Colombia SAS, through its equity interest in GeoPark Colombia Coöperatie. Our shareholders’ agreements with LGI in each As of December 31, 2017, we are not the operator of 21% or sole owner of of Chile and Colombia provides that we have a right of first offer if LGI 38% of the blocks included in our portfolio. See “Item 4. Information on the decides to sell any of its interest in GeoPark Chile or GeoPark Colombia GeoPark 51 Coöperatie. There can be no assurance, however, that we will have the with these assessments, we perform a review of the subject properties funds to purchase LGI’s interest in Chile and/or Colombia and that LGI will that we believe to be generally consistent with industry practices. Our not decide to sell its shares to a third party whose interests may not be review and the review of advisors and independent reserves engineers aligned with ours. 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 In addition, our shareholders’ agreements with LGI in Chile and Colombia their deficiencies and potential recoverable reserves. Inspections may not contain provisions that require GeoPark Chile and GeoPark Colombia always be performed on every well, and environmental conditions are not Coöperatie, the sole shareholder of GeoPark Colombia SAS, to obtain necessarily observable even when an inspection is undertaken. We, advisors LGI’s consent before undertaking certain actions. For example, under or independent reserves engineers may apply different assumptions when the terms of the shareholders’ agreement with LGI in Colombia, LGI must assessing the same field. Even when problems are identified, the seller approve GeoPark Colombia’s annual budget and work programs and may be unwilling or unable to provide effective contractual protection mechanisms for funding any such budget or program, the entering into against all or part of the problems. We often are not entitled to contractual any borrowings other than those provided in an approved budget or indemnification for environmental liabilities and acquire properties on incurred in the ordinary course of business to finance working capital an “as is” basis. Even in those circumstances in which we have contractual needs, the granting of any guarantee or indemnity to secure liabilities of indemnification rights for pre-closing liabilities, it remains possible that parties other than those of our Colombian subsidiary and disposing of the seller will not be able to fulfill its contractual obligations. There can be any material assets other than those provided for in an approved budget no assurance that problems related to the assets or management of the and work program. companies and operations we have acquired, or operations we may acquire or add to our portfolio in the future, will not arise in future, and these Additionally, pursuant to our agreement with LGI in Colombia, we problems could have a material adverse effect on our business, financial and LGI have agreed to vote our common shares or otherwise cause condition and results of operations. GeoPark Colombia Coöperatie to declare dividends only after allowing for retentions of cash for approved work programs and budgets Significant acquisitions and other strategic transactions may involve other capital adequacy requirements, working capital requirements, banking risks, including: covenants associated with any loan entered into by GeoPark Colombia • diversion of our management’s attention to evaluating, negotiating and Coöperatie and GeoPark Colombia SAS and operational requirements. integrating significant acquisitions and strategic transactions; Our inability or failure to obtain LGI’s consent or a delay by LGI in granting • challenge and cost of integrating acquired operations, information its consent may restrict or delay the ability of GeoPark Chile, GeoPark TdF management and other technology systems and business cultures with ours or GeoPark Colombia to take certain actions, which may have an adverse while carrying on our ongoing business; effect on our operations in such countries and on our business, financial • contingencies and liabilities that could not be or were not identified during condition and results of operations. the due diligence process, including with respect to possible deficiencies in Acquisitions that we have completed and any future acquisitions, strategic • challenge of attracting and retaining personnel associated with acquired the internal controls of the acquired operations; and investments, partnerships or alliances could be difficult to integrate and/or operations. identify, could divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely affect our financial For example, we recently acquired a 100% working interest and operatorship results, including impairment of goodwill and other intangible assets. of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina. Our estimates regarding the oil and gas production capabilities of these One of our principal business strategies includes acquisitions of properties, blocks could prove to be incorrect. In addition, development and operating prospects, reserves and leaseholds and other strategic transactions, including costs may be greater than we expect, and we may not be able to successfully in jurisdictions in which we do not currently operate. The successful integrate these blocks. If we fail to realize the benefits we anticipate from this acquisition and integration of producing properties requires an assessment or other acquisitions, our results of operations may be adversely affected. of several factors, including: • recoverable reserves; • future oil and natural gas prices; • development and operating costs; and It is also possible that we may not identify suitable acquisition targets or strategic investment, partnership or alliance candidates. Our inability to identify suitable acquisition targets, strategic investments, partners or • potential environmental and other liabilities. alliances, or our inability to complete such transactions, may negatively affect our competitiveness and growth opportunities. Moreover, if we fail to properly The accuracy of these assessments is inherently uncertain. In connection evaluate acquisitions, alliances or investments, we may not achieve the 52 GeoPark 20-F anticipated benefits of any such transaction and we may incur costs in excess • the amount and timing of actual production; and of what we anticipate. • changes in governmental regulations, taxation or the taxation invariability provisions in our CEOPs. Future acquisitions financed with our own cash could deplete the cash and working capital available to adequately fund our operations. We may also The timing of both our production and our incurrence of expenses in finance future transactions through debt financing, the issuance of our equity connection with the development and production of oil and natural gas securities, existing cash, cash equivalents or investments, or a combination properties will affect the timing and amount of actual future net revenues from of the foregoing. Acquisitions financed with the issuance of our equity proved reserves, and thus their actual value. In addition, the 10% discount securities could be dilutive, which could affect the market price of our stock. factor we use when calculating discounted future net revenues may not be the Acquisitions financed with debt could require us to dedicate a substantial most appropriate discount factor based on interest rates in effect from time to portion of our cash flow to principal and interest payments and could subject time and risks associated with us or the oil and natural gas industry in general. us to restrictive covenants The PN-T-597 Concession Agreement in Brazil may not close. and may require higher levels of capital expenditures than we currently The development of our proved undeveloped reserves may take longer anticipate. Therefore, our proved undeveloped reserves ultimately may not In Brazil, GeoPark Brasil is a party to a class action filed by the Federal be developed or produced. Prosecutor’s Office regarding a concession agreement of exploratory Block PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and As of December 31, 2017, approximately 39% of our net proved reserves are gas bidding round held in November 2013. The Brazilian Federal Court issued developed. Development of our undeveloped reserves may take longer and an injunction against the ANP and GeoPark Brasil in December 2013 that require higher levels of capital expenditures than we currently anticipate. prohibited GeoPark Brasil’s execution of the concession agreement until the Additionally, delays in the development of our reserves or increases in costs ANP conducted studies on whether drilling for unconventional resources would to drill and develop such reserves will reduce the standardized measure contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark value of our estimated proved undeveloped reserves and future net revenues Brasil, at the instruction of the ANP, signed the concession agreement, which estimated for such reserves, and may result in some projects becoming included a clause prohibiting GeoPark Brasil from conducting unconventional uneconomic, causing the quantities associated with these uneconomic exploration activity in the area. Despite the clause containing the prohibition, projects to no longer be classified as reserves. This was due to the uneconomic the judge in the case concluded that the concession agreement should not status of the reserves, given the proximity to the end of the concessions for be executed. Thus, GeoPark Brasil requested that the ANP comply with the these blocks, which does not allow for future capital investment in the blocks. decision and annul the concession agreement, which the ANP’s Board did on There can be no assurance that we will not experience similar delays or October 9, 2015. The annulment reverted the status of all parties to the status increases in costs to drill and develop our reserves in the future, which could quo ante, which maintains GeoPark Brasil’s right to the block. result in further reclassifications of our reserves. There is no assurance that we will be able to enter into a concession agreement We are exposed to the credit risks of our customers and any material in the PN-T-597 Block that would be favorable to our exploration goals. See nonpayment or nonperformance by our key customers could adversely “Item 8—Financial Information—A. Consolidated statements and other affect our cash flow and results of operations. financial information—Legal proceedings.” The present value of future net revenues from our proved reserves will not significant negative effect on their creditworthiness. Severe financial problems necessarily be the same as the current market value of our estimated oil encountered by our customers could limit our ability to collect amounts and natural gas reserves. owed to us, or to enforce the performance of obligations owed to us under Our customers may experience financial problems that could have a contractual arrangements. You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural The combination of declining cash flows as a result of declines in commodity gas reserves. For the year ended December 31, 2017, we have based the prices, a reduction in borrowing basis under reserves-based credit facilities estimated discounted future net revenues from our proved reserves on the 12 and the lack of availability of debt or equity financing may result in a month unweighted arithmetic average of the first-day-of-the-month price for significant reduction of our customers’ liquidity and limit their ability to make the preceding 12 months. Actual future net revenues from our oil and natural payments or perform on their obligations to us. gas properties will be affected by factors such as: • 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 GeoPark 53 face in doing business with these customers may increase. Other customers retain qualified personnel. Our ability to retain our employees is influenced by may also be subject to regulatory changes, which could increase the risk of the economic environment and the remote locations of our exploration blocks, defaulting on their obligations to us. Financial problems experienced by our which may enhance competition for human resources where we conduct our customers could result in the impairment of our assets, a decrease in our activities, thereby increasing our turnover rate. There is strong competition operating cash flows and may also reduce or curtail our customers’ future in our industry to hire employees in operational, technical and other areas, use of our products and services, which may have an adverse effect on our and the supply of qualified employees is limited in the regions where we revenues and may lead to a reduction in reserves. operate and throughout Latin America generally. The loss of any of our key management or other key employees of our technical team or our inability to We may not have the capital to develop our unconventional oil and gas hire and retain new qualified personnel could have a material adverse effect resources. on us. We have identified opportunities for analyzing the potential of We and our operations are subject to numerous environmental, health and unconventional oil and gas resources in some of our blocks and concessions. safety laws and regulations which may result in material liabilities and Our ability to develop this potential depends on a number of factors, costs. including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access We and our operations are subject to various international, foreign, federal, to and availability of equipment, services and personnel and drilling results. state and local environmental, health and safety laws and regulations In addition, as we have no previous experience in drilling and exploiting governing, among other things, the emission and discharge of pollutants into unconventional oil and gas resources, the drilling and exploitation of such the ground, air or water; the generation, storage, handling, use, transportation unconventional oil and gas resources depends on our ability to acquire and disposal of regulated materials; and human health and safety. Our the necessary technology, to hire personnel and other support needed operations are also subject to certain environmental risks that are inherent for extraction or to obtain financing and venture partners to develop such in the oil and gas industry and which may arise unexpectedly and result activities. Because of these uncertainties, we cannot give any assurance in material adverse effects on our business, financial condition and results as to the timing of these activities, or that they will ultimately result in the of operations. Breach of environmental laws could result in environmental realization of proved reserves or meet our expectations for success. administrative investigations and/or lead to the termination of our concessions Our operations are subject to operating hazards, including extreme weather civil environmental actions. For instance, non-governmental organizations events, which could expose us to potentially significant losses. seeking to preserve the environment may bring actions against us or other oil and contracts. Other potential consequences include fines and/or criminal or Our operations are subject to potential operating hazards, extreme weather of the countries in which we operate or require us to pay fines. Additionally, conditions and risks inherent to drilling activities, seismic registration, in Colombia, recent rulings have provided that environmental licenses are exploration, production, development and transportation and storage of crude administrative acts subject to class actions that could eventually result in their oil, such as explosions, fires, car and truck accidents, floods, labor disputes, cancellation, with potential adverse impacts on our E&P Contracts. and gas companies in order to, among other things, halt our activities in any social unrest, community protests or blockades, guerilla attacks, security breaches, pipeline ruptures and spills and mechanical failure of equipment at We have not been and may not be at all times in complete compliance with our or third-party facilities. Any of these events could have a material adverse environmental permits that we are required to obtain for our operations and effect on our exploration and production operations, or disrupt transportation the environmental and health and safety laws and regulations to which we or other process-related services provided by our third-party contractors. are subject. If we fail to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of We are highly dependent on certain members of our management and our permits or the suspension or termination of our operations. If we fail to technical team, including our geologists and geophysicists, and on our obtain, maintain or renew permits in a timely manner or at all, our operations ability to hire and retain new qualified personnel. could be adversely affected, impeded, or terminated, which could have a The ability, expertise, judgment and discretion of our management and our operations. Some environmental licenses related to operation of the Manati technical and engineering teams are key in discovering and developing oil and Field production system and natural gas pipeline have expired. However, the natural gas resources. Our performance and success are dependent to a large operator submitted in a timely manner a request for renewal of those licenses extent upon key members of our management and exploration team, and their and as such this operation is not in default as long as the regulator does not material adverse effect on our business, financial condition or results of loss or departure would be detrimental to our future success. In addition, our state its final position on the renewal. ability to manage our anticipated growth depends on our ability to recruit and 54 GeoPark 20-F We have contracted with and intend to continue to hire third parties to perform below the surface to facilitate a higher flow of hydrocarbons into the services related to our operations. We could be held liable for some or all wellbore. We are contemplating such use of hydraulic fracturing in the environmental, health and safety costs and liabilities arising out of our actions production of oil and natural gas from certain reservoirs, especially shale and omissions as well as those of our block partners, third-party contractors, formations. We currently are not aware of any proposals in Colombia, predecessors or other operators. To the extent we do not address these costs Chile, Brazil, Argentina or Peru to regulate hydraulic fracturing beyond the and liabilities or if we do not otherwise satisfy our obligations, our operations regulations already in place. However, various initiatives in other countries could be suspended, terminated or otherwise adversely affected. There is a with substantial shale gas resources have been or may be proposed risk that we may contract with third parties with unsatisfactory environmental, or implemented to, among other things, regulate hydraulic fracturing health and safety records or that our contractors may be unwilling or unable to practices, limit water withdrawals and water use, require disclosure of cover any losses associated with their acts and omissions. fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. If any Releases of regulated substances may occur and can be significant. Under of the countries in which we operate adopts similar laws or regulations, certain environmental laws and regulations applicable to us in the countries which is something we cannot predict right now, such adoption in which we operate, we could be held responsible for all of the costs relating could significantly increase the cost of, impede or cause delays in the to any contamination at our past and current facilities and at any third-party implementation of any plans to use hydraulic fracturing for unconventional waste disposal sites used by us or on our behalf. Pollution resulting from oil and gas resources. waste disposal, emissions and other operational practices might require us to remediate contamination, or retrofit facilities, at substantial cost. We also could Our indebtedness and other commercial obligations could adversely affect be held liable for any and all consequences arising out of human exposure to our financial health and our ability to raise additional capital, and prevent such substances or for other damage resulting from the release of hazardous us from fulfilling our obligations under our existing agreements and substances to the environment, property or to natural resources, or affecting borrowing of additional funds. endangered species or sensitive environmental areas. We are currently required to, and in the future may need to, plug and abandon sites in certain blocks in As of December 31, 2017, we had US$426.2 million of total indebtedness each of the countries in which we operate, which could result in substantial outstanding on a consolidated basis, consisting primarily of our $425.0 costs. million Notes due 2024, which we issued in September 2017. Substantially all of our debt is secured. As of December 31, 2017, our annual debt service In addition, we expect continued and increasing attention to climate change obligation was US$30.0 million, which mainly consists of the interest issues. Various countries and regions have agreed to regulate emissions of payments under the now repaid Notes due 2020, the now repaid credit greenhouse gases including methane (a primary component of natural gas) facility with Itaú BBA International plc and the Notes due 2024. See “Item and carbon dioxide (a byproduct of oil and natural gas combustion). The 5. Operating and Financial Review and Prospects—B. Liquidity and Capital regulation of greenhouse gases and the physical impacts of climate change Resources—Indebtedness.” Using cash provided by the offering of the Notes in the areas in which we, our customers and the end-users of our products due 2024, we (i) repurchased US$284.0 million aggregate principal amount operate could adversely impact our operations and the demand for our products. of the outstanding Notes due 2020 in September 2017 and redeemed the remaining US$16.0 million aggregate principal amount outstanding in October 2017 and (ii) repaid the credit facility with Itaú BBA International Environmental, health and safety laws and regulations are complex and change plc in September 2017. We are also restricted from entering into financial frequently, and our costs of complying with such laws and regulations may arrangements in some circumstances such as in Colombia where LGI must adversely affect our results of operations and financial condition. See “Item approve GeoPark Colombia’s financial arrangements. See “Item 4. Information 4. Information on the Company—B. Business Overview—Health, safety and on the Company—B. Business Overview—Significant Agreements— environmental matters” and “Item 4. Information on the Company—B. Business Agreements with LGI—LGI Colombia Agreements” for more information. Overview—Industry and regulatory framework.” Legislation and regulatory initiatives relating to hydraulic fracturing and • limit our capacity to satisfy our obligations with respect to our other drilling activities for unconventional oil and gas resources could indebtedness, and any failure to comply with the obligations of any of our increase the future costs of doing business, cause delays or impede our debt instruments, including restrictive covenants and borrowing conditions, plans, and materially adversely affect our operations. could result in an event of default under the agreements governing our Our indebtedness could: indebtedness; Hydraulic fracturing of unconventional oil and gas resources is a process • require us to dedicate a substantial portion of our cash flow from operations that involves injecting water, sand, and small volumes of chemicals into to the payments on our indebtedness, thereby reducing the availability of our the wellbore to fracture the hydrocarbon-bearing rock thousands of feet cash flow to fund acquisitions, working capital, capital expenditures and other GeoPark 55 general corporate purposes; In addition, the oil and gas industry has become increasingly dependent • place us at a competitive disadvantage compared to certain of our on digital technologies to conduct day-to-day operations including competitors that have less debt; certain exploration, development and production activities. For example, • • limit our ability to borrow additional funds; software programs are used to interpret seismic data, manage drilling rigs, in the case of our secured indebtedness, lose assets securing such conduct reservoir modeling and reserves estimation, and to process and indebtedness upon the exercise of security interests in connection with a record financial and operating data. We depend on digital technology, default; including information systems and related infrastructure as well as cloud • make us more vulnerable to downturns in our business or the economy; application and services, to process and record financial and operating data, and communicate with our employees and business partners, analyze seismic and • limit our flexibility in planning for, or reacting to, changes in our operations drilling information, estimate quantities of oil and gas reserves and for many or business and the industry in which we operate. other activities related to our business. Our business partners, including The indenture governing our Notes due 2024 includes covenants and financial institutions, are also dependent on digital technology. As restricting dividend payments. For a description, see “Item 5. Operating dependence on digital technologies has increased, cyber incidents, including and Financial Review and Prospects—B. Liquidity and Capital Resources— deliberate attacks or unintentional events, have also increased. vendors, service providers, co-venturers, purchasers of our production, Indebtedness—Notes due 2024.” A cyber-attack could include gaining unauthorized access to digital systems As a result of these restrictive covenants, we are limited in the manner for purposes of misappropriating assets or sensitive information, corrupting in which we conduct our business, and we may be unable to engage data, or causing operational disruption, or result in denial-of-service on in favorable business activities or finance future operations or capital websites. Our technologies, systems, networks, and those of our business needs. We have in the past been unable to meet incurrence tests under partners may become the target of cyber-attacks or information security the indenture governing our now repaid Notes due 2020, which limited breaches that could result in the unauthorized release, gathering, monitoring, our ability to incur indebtedness. Failure to comply with the restrictive misuse, loss or destruction of proprietary and other information, or other covenants included in our Notes due 2024 would not trigger an event of disruption of our business operations. Our employees have been and will default. continue to be targeted by parties using fraudulent “spam” and “phishing” emails to misappropriate information or to introduce viruses or other Similar restrictions could apply to us and our subsidiaries when we malware through “trojan horse” programs to our computers. These emails refinance or enter into new debt agreements which could intensify the risks appear to be legitimate emails sent by us but direct recipients to fake described above. websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or Our business could be negatively impacted by security threats, including download malware. Despite our efforts to mitigate “spoof” and “phishing” cybersecurity threats as well as other disasters, and related disruptions. emails through education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure. Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability Certain cyber incidents, such as surveillance, may remain undetected for to expand and continually update this infrastructure in response to an extended period. A cyber incident involving our information systems our changing needs. It is critical to our business that our facilities and and related infrastructure, or that of our business partners, could disrupt infrastructure remain secure. Although we have implemented internal control our business plans and negatively impact our operations. Although to date procedures to assure the security of our data, we cannot guarantee that these we have not experienced any significant cyber-attacks, there can be no measures will be sufficient for this purpose. The ability of the information assurance that we will not be the target of cyber-attacks in the future or suffer technology function to support our business in the event of a security breach such losses related to any cyber-incident. As cyber threats continue to evolve, or a disaster such as fire or flood and our ability to recover key systems and we may be required to expend significant additional resources to continue to information from unexpected interruptions cannot be fully tested and there modify or enhance our protective measures or to investigate and remediate is a risk that, if such an event actually occurs, we may not be able to address any information security vulnerabilities. immediately the repercussions of a breach. In the event of a breach, key information and systems may be unavailable for a number of days leading to Risks relating to the countries in which we operate an inability to conduct our business or perform some business processes in a timely manner. We have implemented strategies to mitigate the impact from Our operations may be adversely affected by political and economic these types of events. circumstances in the countries in which we operate and in which we may operate in the future. 56 GeoPark 20-F All of our current operations are located in South America. If local, regional production activities may be substantially affected by factors which could have or worldwide economic trends adversely affect the economy of any of the a material adverse effect on our results of operations and financial condition. We countries in which we have investments or operations, our financial condition cannot guarantee that current programs and policies that apply to the oil and and results from operations could be adversely affected. gas industry will remain in effect. Oil and natural gas exploration, development and production activities are Our operations may also be adversely affected by laws and policies of the subject to political and economic uncertainties (including but not limited to jurisdictions, including Bermuda, Colombia, Chile, Brazil, Peru, Argentina, Spain, changes in energy policies or the personnel administering them), changes the United Kingdom, the Netherlands and other jurisdictions in which we do in laws and policies governing operations of foreign-based companies, business, that affect foreign trade and taxation, and by uncertainties in the expropriation of property, cancellation or modification of contract rights, application of, possible changes to (or to the application of) tax laws in these revocation of consents or approvals, the obtaining of various approvals jurisdictions. For example, in 2016 the Colombian government introduced tax from regulators, foreign exchange restrictions, price controls, currency reforms with provisions that are effective January 1, 2017. See Note 16 to our fluctuations, royalty increases and other risks arising out of foreign Consolidated Financial Statements. With regards to Chile, although our CEOPs governmental sovereignty, as well as to risks of loss due to civil strife, acts of have protection against tax changes through invariability tax clauses, potential war and community-based actions, such as protests or blockades, guerilla issues may arise on certain aspects not clearly defined in current or future tax activities, terrorism, acts of sabotage, territorial disputes and insurrection. reforms. In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in Changes in any of these laws or policies or the implementation thereof, and such tax laws (or the application thereof ), each of which could result in an uncertainty over potential changes in policy or regulations affecting any increase in our tax liabilities. These risks are higher in developing countries, of the factors mentioned above or other factors in the future may increase such as those in which we conduct our activities. the volatility of domestic securities markets and securities issued abroad by companies operating in these countries, which could materially and adversely The main economic risks we face and may face in the future because of our affect our financial position, results of operations and cash flows. Furthermore, operations in the countries in which we operate include the following: we may be subject to the exclusive jurisdiction of courts outside the United • difficulties incorporating movements in international prices of crude oil and States or may not be successful in subjecting non-U.S. persons to the jurisdiction exchange rates into domestic prices; of courts in the United States, which could adversely affect the outcome of • the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s such dispute. Changes in tax laws may result in increases in our tax payments, or Brazil’s relations with multilateral credit institutions, such as the IMF, will which could materially adversely affect our profitability and increase the impact negatively on capital controls, and result in a deterioration of the prices of our products and services, restrict our ability to do business in our business climate; existing and target markets and cause our results of operations to suffer. There • 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 10% of our revenues as of December 31, guerilla activities, social unrest, local economic conditions, political disruption, 2017. 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 Prosecutor’s Office in connection with corruption allegations (the “Lava GeoPark 57 Jato” investigations). Depending on the duration and outcome of such development and ownership of oil, environmental protection, health investigations, the companies involved may face downgrades from rating and safety or labor relations, which may negatively affect our ability to agencies, funding restrictions and a reduction in their revenues. Given the undertake exploration and development activities in respect of present significance of the companies under investigation including Petrobras, this and future properties, as well as our ability to raise funds to further such could adversely affect Brazil’s growth prospects and could have a protracted activities. Any delays in receiving government approvals in such countries effect on the oil and gas industry. In addition to the recent economic crisis, may delay our operations or may affect the status of our contractual protests, strikes and corruption scandals have led to a fall in confidence. arrangements or our ability to meet contractual obligations. We depend on maintaining good relations with the respective host Oil and gas operators are subject to extensive regulation in the countries in governments and national oil companies in each of our countries of operation. which we operate. The success of our business and the effective operation of the fields in each of our The Colombian, Chilean, Brazilian, Peruvian and Argentine hydrocarbons countries of operation depend upon continued good relations and cooperation industries are subject to extensive regulation and supervision by their with applicable governmental authorities and agencies, including national oil respective governments in matters such as the environment, social companies such as Ecopetrol, ENAP, Petrobras, Petroperu and YPF. For instance, responsibility, tort liability, health and safety, labor, the award of exploration for the year ended December 31, 2017, 100% of our crude oil and condensate and production contracts, the imposition of specific drilling and exploration sales in Chile were made to ENAP, the Chilean state-owned oil company. In obligations, taxation, foreign currency controls, price controls, capital addition, our Brazilian operations in BCAM-40 Concession provide us with a long- expenditures and required divestments. In some countries in which term off-take contract with Petrobras, the Brazilian state-owned company that we operate, such as Colombia, we are required to pay a percentage of covers 100% of net proved gas reserves in the Manati Field, one of the largest our expected production to the government as royalties. See “Item 4. non-associated gas fields in Brazil. If we, the respective host governments and the Information on the Company—B. Business Overview—Industry and national oil companies are not able to cooperate with one another, it could have regulatory framework—Colombia” and see Note 32(a) to our Consolidated an adverse impact on our business, operations and prospects. Financial Statements. Oil and natural gas companies in Colombia, Chile, Brazil, Peru and Argentina For example, in Brazil there is potential liability for personal injury, property do not own any of the oil and natural gas reserves in such countries. damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of operations Under Colombian, Chilean, Brazilian, Peruvian and Argentine law, all or our being subjected to administrative, civil and criminal penalties, which onshore and offshore hydrocarbon resources in these countries are owned could have a material adverse effect on our financial condition and expected by the respective sovereign. Although we are the operator of the majority results of operations. We expect to also operate in a consortium in some of of the blocks and concessions in which we have a working and/or economic our concessions, which, under the Brazilian Petroleum Law, establishes joint interest and generally have the power to make decisions as how to market and strict liability among consortium members, and failure to maintain the the hydrocarbons we produce, the Chilean, Colombian, Brazilian, Peruvian appropriate licenses may result in fines from the ANP, ranging from R$10 and Argentine governments have full authority to determine the rights, to R$500 million. In addition, there is a contractual requirement in Brazilian royalties or compensation to be paid by or to private investors for the concession agreements regarding local content, which has become a exploration or production of any hydrocarbon reserves located in their significant issue for oil and natural gas companies operating in Brazil given respective countries. the penalties related with breaches thereof. The local content requirement will also apply to the production sharing contract regime. See “Item 4. If these governments were to restrict or prevent concessionaires, including Information on the Company—B. Business Overview—Our operations— us, from exploiting oil and natural gas reserves, or otherwise interfered Operations in Brazil.” with our exploration through regulations with respect to restrictions on future exploration and production, price controls, export controls, foreign Significant expenditures may be required to ensure our compliance exchange controls, income taxes, expropriation of property, environmental with governmental regulations related to, among other things, licenses legislation or health and safety, this could have a material adverse effect on for drilling operations, environmental matters, drilling bonds, reports our business, financial condition and results of operations. concerning operations, the spacing of wells, unitization of oil and natural gas Additionally, we are dependent on receipt of government approvals or permits to develop the concessions we hold in some countries. There can Colombia has experienced and continues to experience internal security issues be no assurance that future political conditions in the countries in which that have had or could have a negative effect on the Colombian economy. accumulations, local content policy and taxation. we operate will not result changes to policies with respect to foreign 58 GeoPark 20-F In 2016, the Colombian government and the Revolutionary Armed Forces • domestic and international economic, legal and regulatory factors of Colombia (FARC) signed a peace agreement, pursuant to which the FARC unrelated to our performance. agreed to demobilize its troops and to hand over its weapons to a United • variations in our quarterly operating results; Nations mission within 180 days. Our business, financial condition and results • volatility in our industry, the industries of our customers and the global of operations could be adversely affected by rapidly changing economic or securities markets; social conditions, including the Colombian government’s response to current • changes in our dividend policy; peace agreements and negotiations with other groups, including the ELN, • risks relating to our business and industry, including those discussed above; which may result in legislation that increases our tax burden or that of other • strategic actions by us or our competitors; Colombian companies. • actual or expected changes in our growth rates or our competitors’ growth rates; ELN has targeted crude oil pipelines in Colombia, including the Caño Limón- • investor perception of us, the industry in which we operate, the investment Coveñas pipeline, and other related infrastructure, disrupting the activities of opportunity associated with our common shares and our future performance; certain oil and natural gas companies and resulting in unscheduled shut- • adverse media reports about us or our directors and officers; downs of transportation systems. These activities, their possible escalation • addition or departure of our executive officers; and the effects associated with them have had and may have in the future a • change in coverage of our company by securities analysts; negative impact on the Colombian economy or on our business, which may • trading volume of our common shares; affect our employees or assets. • future issuances of our common shares or other securities; In addition, from time to time, community protests and blockades may arise • the release or expiration of transfer restrictions on our outstanding near our operations in Colombia, which could adversely affect our business, common shares. • terrorist acts; financial condition or results of operations. Risks related to our common shares We have never declared or paid, and do not expect to pay in the foreseeable future, cash dividends on our common shares, and, consequently, your only opportunity to achieve a return on your 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 of “NYSE”) on February 7, 2014, and as a result have a limited trading history. directors and our shareholders, and will depend on many factors, such as our We cannot predict the extent to which investor interest in our company will results of operations, financial condition, cash requirements, prospects and maintain an active trading market on the NYSE, or how liquid that market other factors. Due to losses resulting from the oil price decline, accumulated will be in the future. losses amount to US$283.9 million as of December 31, 2017. The market price of our common shares may be volatile and may be 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, including our and their agreements with LGI, in making distributions to us. GeoPark 59 As a holding company, our only material assets are our cash on hand, the shares were outstanding as of December 31, 2017. We cannot predict the equity interests in our subsidiaries and other investments. Our principal size of future issuances of our common shares or the effect, if any, that source of revenue and cash flow is distributions from our subsidiaries. Thus, future sales and issuances of shares would have on the market price of our our ability to service our debt, finance acquisitions and pay dividends to our common shares. stockholders in the future is dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to make upstream cash Provisions of the Notes due 2024 could discourage an acquisition of us by distributions to us. Our subsidiaries are and will be separate legal entities, a third party. and although they may be wholly-owned or controlled by us, they have no obligation to make any funds available to us, whether in the form of Certain provisions of the Notes due 2024 could make it more difficult or loans, dividends, distributions or otherwise. The ability of our subsidiaries more expensive for a third party to acquire us, or may even prevent a third to distribute cash to us will also be subject to, among other things, party from acquiring us. For example, upon the occurrence of a fundamental restrictions that are contained in our subsidiaries’ financing and joint change, holders of the Notes due 2024 will have the right, at their option, to venture agreements, availability of sufficient funds in such subsidiaries require us to repurchase all of their notes at a purchase price equal to 101% of and applicable state laws and regulatory restrictions. Claims of creditors the principal amount thereof plus any accrued and unpaid interest (including of our subsidiaries generally will have priority as to the assets of such any additional amounts, if any) to the date of purchase. By discouraging an subsidiaries over our claims and claims of our creditors and stockholders. acquisition of us by a third party, these provisions could have the effect of To the extent the ability of our subsidiaries to distribute dividends or other depriving the holders of our common shares of an opportunity to sell their payments to us could be limited in any way, our ability to grow, pursue common shares at a premium over prevailing market prices. business opportunities or make acquisitions that could be beneficial to our businesses, or otherwise fund and conduct our business could be materially Certain shareholders have substantial control over us and could limit your limited. ability to influence the outcome of key transactions, including a change of We may not be able to fully control the operations and the assets of control. our joint ventures and we may not be able to make major decisions or Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief take timely actions with respect to our joint ventures unless our joint Executive Officer, Mr. Jamie Coulter, director, and Mr. Juan Cristóbal Pavez, venture partners agree. For example, we have entered into a shareholders’ director, control 32.3% of our outstanding common shares as of March 15, agreement and members’ agreement with LGI in Chile and Colombia, 2018, holding the shares either directly or through privately held funds. As respectively, that set the bases for the amount of dividends to be declared a result, these shareholders, if acting together, would be able to influence or returned to us, certain aspects related to the management of our Chilean or control matters requiring approval by our shareholders, including the and Colombian businesses, respectively, the incurrence of indebtedness, election of directors and the approval of amalgamations, mergers or other liens and our ability to sell certain assets. See “—Risks relating to our extraordinary transactions. They may also have interests that differ from business—LGI, our strategic partner in Chile and Colombia, may not consent yours and may vote in a way with which you disagree and which may to our taking certain actions or may eventually decide to sell its interest be adverse to your interests. The concentration of ownership may have in our Chilean and Colombian operations to a third party.” We may, in the the effect of delaying, preventing or deterring a change of control of our future, enter into other joint venture agreements imposing additional company, could deprive our stockholders of an opportunity to receive a restrictions on our ability to pay dividends. premium for their common shares as part of a sale of our company and Sales of substantial amounts of our common shares in the public market, or Major Shareholders and Related Party Transactions—A. Major shareholders” the perception that these sales may occur, could cause the market price of for a more detailed description of our share ownership. might ultimately affect the market price of our common shares. See “Item 7. our common shares to decline. We may issue additional common shares or convertible securities in the and NYSE governance standards than domestic U.S. issuers. This may future, for example, to finance potential acquisitions of assets, which we afford less protection to holders of our common shares, and you may not intend to continue to pursue. Sales of substantial amounts of our common receive corporate and company information and disclosure that you are shares in the public market, or the perception that these sales may occur, accustomed to receiving or in a manner in which you are accustomed to As a foreign private issuer, we are subject to different U.S. securities laws could cause the market price of our common shares to decline. This could receiving it. also impair our ability to raise additional capital through the sale of our equity securities. Under our memorandum of association, we are authorized As a foreign private issuer, the rules governing the information that we to issue up to 5,171,949,000 common shares, of which 60,596,219 common disclose differ from those governing U.S. corporations pursuant to the 60 GeoPark 20-F Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although exemption from new or revised accounting standards, and, therefore, we will we intend to report quarterly financial results and report certain material be subject to the same new or revised accounting standards as other public events, we are not required to file quarterly reports on Form 10-Q or provide companies that are not emerging growth companies. current reports on Form 8-K disclosing significant events within four days of their occurrence and our quarterly or current reports may contain less Our internal controls over financial reporting may not be effective which information than required under U.S. filings. In addition, we are exempt could have a significant and adverse effect on our business and reputation. from the Section 14 proxy rules, and proxy statements that we distribute will not be subject to review by the SEC. Our exemption from Section 16 rules We have evaluated our internal controls for our financial reporting and have regarding sales of common shares by insiders means that you will have less determined our controls were effective for the fiscal year ended December data in this regard than shareholders of U.S. companies that are subject to 31, 2017. As long as we qualify as an “emerging growth company” as defined the Exchange Act. As a result, you may not have all the data that you are by the JOBS Act, we will not be required to obtain an auditor’s attestation accustomed to having when making investment decisions. For example, our report on our internal controls in future annual reports on Form 20-F as officers, directors and principal shareholders are exempt from the reporting otherwise required by Section 404(b) of the Sarbanes-Oxley Act. Accordingly, and “short-swing” profit recovery provisions of Section 16 of the Exchange our independent registered public accounting firm did not perform an Act and the rules thereunder with respect to their purchases and sales of our audit of our internal control over financial reporting for the fiscal year ended common shares. The periodic disclosure required of foreign private issuers December 31, 2017. Had our independent registered public accounting firm is more limited than that required of domestic U.S. issuers and there may performed an attestation on our internal control over financial reporting, it is therefore be less publicly available information about us than is regularly possible that their opinion on our internal controls could have differed from published by or about U.S. public companies. See “Item 10. Additional ours which could harm our reputation and share value. Information—H. Documents on display.” As a foreign private issuer, we will be exempt from complying with certain common shares which could result in the delay or denial of any transfers you There are regulatory limitations on the ownership and transfer of our corporate governance requirements of the NYSE applicable to a U.S. issuer, might seek to make. including the requirement that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve The Bermuda Monetary Authority (the “BMA”), must specifically approve all any equity issuance by us which represents 20% or more of our outstanding issuances and transfers of securities of a Bermuda exempted company like us common shares. As the corporate governance standards applicable to us unless it has granted a general permission. We are able to rely on a general are different than those applicable to domestic U.S. issuers, you may not permission from the BMA to issue our common shares, and to freely transfer our have the same protections afforded under U.S. law and the NYSE rules as common shares as long as the common shares are listed on the NYSE and/or shareholders of companies that do not have such exemptions. other appointed stock exchange, to and among persons who are non-residents of Bermuda for exchange control purposes. Any other transfers remain subject We are an “emerging growth company,” and we cannot be certain if the to approval by the BMA and such approval may be denied or delayed. reduced disclosure requirements applicable to emerging growth companies will make our common shares less attractive to investors. We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. We are an “emerging growth company,” as defined in the Jumpstart our Business Startups Act of 2012 (the “JOBS Act”), and for as long as we continue We are incorporated as an exempted company under the laws of Bermuda to be an “emerging growth company” we may choose to take advantage of and substantially all of our assets are located in Colombia, Chile, Argentina, certain exemptions from various reporting requirements that are applicable to Brazil and Peru. In addition, most of our directors and executive officers other public companies that are not “emerging growth companies,” including, reside outside the United States and all or a substantial portion of the but not limited to, not being required to comply with the auditor attestation assets of such persons are located outside the United States. As a result, requirements of Section 404(b) of the Sarbanes Oxley Act. We cannot predict it may be difficult or impossible to effect service of process within the if investors will find our common shares less attractive because we will rely on United States upon us, or to recover against us on judgments of U.S. courts, these exemptions. If some investors find our common shares less attractive as including judgments predicated upon the civil liability provisions of the a result, there may be a less active trading market for our common shares and U.S. federal securities laws. Further, no claim may be brought in Bermuda our share price may be more volatile. against us or our directors and officers in the first instance for violation of U.S. federal securities laws because these laws have no extraterritorial Under the JOBS Act, emerging growth companies can delay adopting new application under Bermuda law and do not have force of law in Bermuda. or revised accounting standards until such time as those standards apply to However, a Bermuda court may impose civil liability, including the private companies. We have irrevocably elected not to avail ourselves of this GeoPark 61 Information on the company possibility of monetary damages, on us or our directors and officers if the We were incorporated as an exempted company pursuant to the laws of facts alleged in a complaint constitute or give rise to a cause of action Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, under Bermuda law. our shareholders approved a change in our name to GeoPark Limited, effective from July 31, 2013. We maintain a registered office in Bermuda at There is no treaty in force between the United States and Bermuda Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. providing for the reciprocal recognition and enforcement of judgments in Our principal executive offices are located at Nuestra Señora de los Ángeles civil and commercial matters. As a result, whether a United States judgment 179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, Street would be enforceable in Bermuda against us or our directors and officers 94 N° 11-30, 8, 9, 8th floor, Bogotá, Colombia, telephone number +57 1 743 depends on whether the U.S. court that entered the judgment is recognized 2337, and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number by the Bermuda court as having jurisdiction over us or our directors and +5411 4312 9400. Our website is www.geo-park.com. The information on our officers, as determined by reference to Bermuda conflict of law rules. A website does not constitute part of this annual report. 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 Our Company judgment debtor had submitted to the jurisdiction of the U.S. court, and We are a leading independent oil and natural gas exploration and production the issue of submission and jurisdiction is a matter of Bermuda (not U.S.) (“E&P”) company with operations in Latin America and a proven track record law. of growth in production and reserves since 2006. We operate in Colombia, Chile, Brazil, Peru and Argentina. We are focused on Latin America because In addition, and irrespective of jurisdictional issues, the Bermuda courts we believe it is one of the most important regions globally in terms of will not enforce a U.S. federal securities law that is either penal or contrary hydrocarbon potential, with less presence of independent E&P companies to Bermuda public policy. An action brought pursuant to a public or penal compared to the United Stated and Canada. In this region, much of the law, the purpose of which is the enforcement of a sanction, power or right acreage has historically been controlled or owned by state-owned companies. at the instance of the state in its sovereign capacity, will not be entertained We believe that these factors create an opportunity for smaller, more agile by a Bermuda court. Certain remedies available under the laws of U.S. companies like us to build a long-term business. jurisdictions, including certain remedies under U.S. federal securities laws, would not be available under Bermuda law or enforceable in a Bermuda We produced a net average of 27.6 mboepd during the year ended December court, as they would be contrary to Bermuda public policy. 31, 2017, of which 79%, 10% and, 11% were, respectively, in Colombia, Chile, and Brazil, and of which 83% was oil. As of the third quarter of 2017, we were The transfer of our common shares may be subject to capital gains taxes ranked as the second largest private oil operator in Colombia, where we made pursuant to indirect transfer rules in Chile. the largest new oil field discovery in the last 20 years. We are the first private In September 2012, Chile established “indirect transfer rules,” which impose Petroperu in its return to the upstream business in Peru. We partnered with taxes, under certain circumstances, on capital gains resulting from indirect Petrobras in one of Brazil’s largest producing gas fields and we have recently transfers of shares, equity rights, interests or other rights in the equity, increased our activities in Argentina with a new oil field discovery and project oil and gas operator in Chile and we are operating the inaugural project of control or profits of a Chilean entity, as well as on transfers of other assets and acquisition. property of permanent establishments or other businesses in Chile (“Chilean Assets”). As we indirectly own Chilean Assets, the indirect transfer rules We have built our company around three principal capabilities: would apply to transfers of our common shares provided certain conditions • as an Explorer, which is our ability, experience, methodology and creativity outside of our control are met. If such conditions were present and as a to find and develop oil and gas reserves in the subsurface, based on the best result the indirect transfer rules were to apply to sales of our common shares, science, solid economics and ability to take the necessary managed risks. such sales would be subject to indirect transfer tax on the capital gain that • as an Operator, which is our ability to execute in a timely manner and to may be determined in each transaction. For a description of the indirect have the know-how to profitably drill for, produce, treat, transport and sell transfer rules and the conditions of their application see “Item 10. Additional our oil and gas – with the drive and persistence to find solutions, overcome Information—E. Taxation—Chilean tax on transfers of shares.” obstacles, seize opportunities and achieve results. ITEM 4. INFORMATION ON THE COMPANY balance and portfolio of upstream assets in the right hydrocarbon basins in • as a Consolidator, which is our ability and initiative to assemble the right the right regions with the right partners and at the right price – coupled with A. History and development of the company the visions and skills to transform and improve value above ground. General 62 GeoPark 20-F We believe that our risk and capital management policies have enabled us to compile a geographically diverse portfolio of properties that Also in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14% balances exploration, development and production of oil and gas. These equity interest in GeoPark TdF for US$148.0 million. Our agreement with attributes have also allowed us to raise capital and to partner with premier LGI in the Tierra del Fuego Blocks allows us to earn back up to 12% equity international companies. Most importantly, we believe we have developed a participation in GeoPark TdF, depending on the success of our operations in distinctive culture within our organization that promotes and rewards trust, Tierra del Fuego. See “Item 10. Additional Information—C. Material contracts.” partnership, entrepreneurship and merit. Consistent with this approach, 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 Panama, which merged into GeoPark Colombia SAS (“Luna”) and (iii) GeoPark 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 in Colombia History that currently includes working interests and/or economic interests in 6 blocks located in the Llanos and Magdalena Basins. We have also a right to We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park, acquire and operate 85% of the Tiple Block in Colombia, subject to drilling an who have over 30 years of international oil and natural gas experience, exploratory well resulting in a commercial discovery. respectively, and who collectively hold approximately 25% of our common shares as of the date of this annual report. Mr. O’Shaughnessy currently serves In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia as our Chairman and Mr. Park currently serves as our Chief Executive Officer by making a US$14.9 million capital contribution and assuming the existing and Deputy Chairman. debt for an amount of US$4.9 million and the commitment to provide additional funding to cover LGI’s share of required future investments in In 2006, after demonstrating our technical expertise and committing to Colombia. Our agreement with LGI in Colombia allows us to earn back up to an exploration and development plan, we obtained a 100% operating 12% equity participation in GeoPark Colombia, depending on the success working interest in the Fell Block from the Republic of Chile. Also in 2006, of our operations in Colombia. See “Item 10. Additional Information—C. the International Finance Corporation (the “IFC”), a member of the World Material contracts.” We believe our partnership with LGI represents a positive Bank Group, became one of our principal shareholders, and we listed our independent assessment and validation of the quality of our Chilean and common shares on AIM, a market operated by the London Stock Exchange Colombian asset inventory, the extent of our technical and operational plc, in an initial public offering of common shares outside the United States. expertise and the ability of our management to structure and effect Subsequently, in 2008 and 2009, we issued and sold additional common significant transactions. shares outside the United States. In 2008 and 2009, we continued our growth in Chile by acquiring operating of 7.50% senior secured notes due 2020. We repurchased US$284.0 million working interests in each of the Otway and Tranquilo Blocks, and by forming aggregate principal amount of the outstanding Notes due 2020 in September partnerships with Pluspetrol, Wintershall, Methanex and IFC. 2017 and redeemed the remaining US$16.0 million aggregate principal In February 2013, we issued US$300.0 million aggregate principal amount amount outstanding in October 2017. In 2010, we formed a strategic partnership with LGI, a Korean conglomerate, to jointly acquire and develop upstream oil and gas projects in Latin America. In May 2013, we entered into agreements to expand our operations to Brazil. LGI’s business includes a portfolio of energy and raw material projects, including oil and gas projects in the Middle East and in Southeast and Central See “—B. Business Overview—Our operations—Operations in Brazil.” Asia. In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over- In 2011, ENAP awarded us the opportunity to obtain operating working allotment option granted to and exercised by the underwriters, through the interests in each of the Isla Norte, Flamenco and Campanario Blocks in Tierra issuance of 13,999,700 common shares. del Fuego, Chile, which we refer to collectively as the Tierra del Fuego Blocks, and in 2012, jointly with ENAP, we entered into CEOPs with Chile for the In August 2014, we and Pluspetrol were awarded two exploration licenses exploration and exploitation of hydrocarbons within these blocks. in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza GeoPark 63 Bidding Round in Argentina. The blocks are located in the Neuquén Basin, In December 2017, we agreed to purchase from Pluspetrol, a private oil and Argentina’s largest producing hydrocarbon basin. gas company with strong presence across Latin America, a 100% working interest and operatorship of the Aguada Baguales, El Porvenir and Puesto In October 2014, we entered into an agreement to expand our footprint Touquet blocks in Argentina. We entered into an asset purchase agreement into Peru through the acquisition of Morona Block in a joint operation with with Pluspetrol, dated December 18, 2017 (the “APA”). The transaction closed Petroperu. Petroperu awarded a 75% working interest in and operatorship of on March 27, 2018. the Morona Block to us. The agreement was subject to regulatory approval, which was completed in December 2016, as described below. See “Item 3. Key Information—D. Risk factors—Risks relating to our business.” In July 2015, we signed a farm-in agreement with Wintershall for the CN-V B. Business Overview Block in Argentina. In October 2015, we were awarded four exploratory blocks in the Brazilian (“E&P”), company with operations in Latin America and a proven track record ANP Bid Round 13 in the Reconcavo and Potiguar Basins. of growth in production and reserves since 2006. We operate in Colombia, We are a leading independent oil and natural gas exploration and production Chile, Brazil, Peru and Argentina. In December 2015, as part of our long term effort to build an upstream platform in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo We have grown our business through drilling, developing and producing oil Alfa for onshore projects, however, no blocks were awarded. and gas, winning new licenses and acquiring strategic assets and businesses. In December 2016, we obtained final regulatory approval for our acquisition development efforts, drilling program, long-term strategic partnerships and of the Morona Block in Peru. The Joint Investment and Operating Agreement alliances with key industry participants, accessing debt and equity capital dated October 1, 2014 and its amendments were closed on December 1, 2016 markets, developing and retaining a technical team with vast experience following the issuance of Supreme Decree 031-2016-MEM. and creating a successful track record of finding and producing oil and gas Since our inception, we have supported our growth through our prospect In September 2017, we issued US$425.0 million aggregate principal amount team of geologists, geophysicists and engineers, including professionals of 6.50% senior secured notes due 2024. The net proceeds from the Notes with specialized expertise in the geology of Colombia, Chile, Brazil, Peru and in Latin America. A key factor behind our success ratio is our experienced were used by us (i) to make a capital contribution to our wholly-owned Argentina. subsidiary, GeoPark Latin America Limited Agencia en Chile, providing it with sufficient funds to fully repay the 7.50% senior secured notes due 2020 The following map shows the countries in which we have blocks with working and to pay any related fees and expenses, including a call premium, and (ii) and/or economic interests as of December 31, 2017. For information on our for general corporate purposes, including capital expenditures, such as the working interests in each of these blocks, see “—Our assets” below. acquisition of Aguada Baguales, El Porvenir and Puesto Touquet blocks in Neuquen basin in Argentina, and to repay existing indebtedness, including the Itaú loan. Additionally, we were awarded one exploratory block in the Brazilian ANP Bid Round 14 in the Potiguar Basin. 64 GeoPark 20-F Brazil Blocks POT-T-619 REC-T-94 BCAM-40 Manati SEAL-T-268 POT-T-747 POT-T-882 POT-T-785 REC-T-93 REC-T-128 PN-T-597(2) ATLANTIC OCEAN Argentina Blocks Sierra del Nevado Puelen CN-V Colombia Blocks COLOMBIA La Cuerva Llanos 34 Yamu Llanos 32 Abanico VIM-3 Tiple(1) Chile Blocks Fell Isla Norte Campanario Flamenco Tranquilo Peru Block Morona PERU BRAZIL PA CIFIC OCEAN ARGENTINA CHILE (1) The Tiple Block is subject to drilling an exploratory well resulting in a commercial discovery. 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.” GeoPark 65 The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2017. For the year ended December 31 2017 (1) Country Colombia Chile Brazil Peru Total Oil (mmbbl) Gas (bcf ) (mmboe) Oil equivalent 65.5 4.1 0.1 18.7 88.4 - 20.0 23.8 - 43.8 65.5 7.5 4.0 18.7 95.7 Revenues (in thousands of US$) 263,076 32,738 34,238 — 330,052 %Oil 100% 55% 3% 100% 92% % of total revenues 80% 10% 10% -% 100% (1) Does not include Argentina, as reserves in Argentina have not been declared commercially viable as of December 31, 2017. Our commitment to growth has translated into a strong compounded annual growth rate (“CAGR”), of 20% for production in the period from 2013 to 2017, as measured by boepd in the table below. For the year ended December 31, Average net production (mboepd) % oil 2017 27.6 83% 2016 22.4 75% 2015 20.4 74% 2014 19.7 74% 2013 13.5 82% 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, 2017. Average daily production For the year ended December 31, 2017 Oil production Total crude oil production (bopd) Natural gas production Total natural gas production (mcf/day) Oil and natural gas production Colombia Chile Brazil Argentina Total 21,718 1,000 42 414 11,317 17,209 4 - 4 22,764 28,940 27,586 Total oil and natural gas production (mboed) 21,787 2,885 2,910 Our assets We have a well-balanced portfolio of assets that includes working and/or economic interests in 24 hydrocarbon blocks, 23 of which are onshore blocks, including 7 in production as of December 31, 2017. 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, 2017, the blocks in Colombia, Chile, Brazil and Peru in which we have a working interest had 95.7 mmboe of net proved reserves, with 68%, 8%, 4% and 20% of such net proved reserves located in Colombia, Chile, Brazil and Peru, respectively. We produced a net average of 27.6 mboepd during the year ended December 31, 2017 of which 79%, 10%, and 11%, were in Colombia, Chile and Brazil, 66 GeoPark 20-F respectively, and of which 83% was oil. and plays. See “—Our operations—Operations in Peru.” We are the operator of a majority of the blocks in which we have a working Strong cash flow interest. Our strengths We benefit from strong cash flow from operating activities. For the year ended December 31, 2017, cash provided by operating activities was US$142.2 million. Our cash flow from operating activities plays a significant role in We believe that we benefit from the following competitive strengths: funding our capital expenditures. High quality and diversified asset base built through a successful track Significant drilling inventory and resource potential from existing asset base record of organic growth and acquisitions Our portfolio includes large land holdings in high-potential hydrocarbon basins Our assets include a diverse portfolio of oil- and natural gas-producing reserves, and blocks with multiple drilling leads and prospects in different geological operating infrastructure, operating licenses and valuable geological surveys in formations, which provide a number of attractive opportunities with varying Latin America. Throughout our history, we have delivered continuous growth in levels of risk. Our drilling inventory and our development plans target locations our production, and our management team has been able to identify under- that provide attractive economics and support a predictable production profile , exploited assets and turn them into valuable, productive assets, and to allocate as demonstrate by our recent expansions in Colombia and Peru. resources effectively based on prevailing conditions. Our geoscience team continues to identify new potential accumulations and • Chile. In 2002, we acquired a non-operating working interest in the Fell Block expand our inventory of prospects and drilling opportunities. in Chile, which at the time had no material oil and gas production or reserves despite having been actively explored and drilled over the course of more Platform and Funding than 50 years. Since 2006, when we became the operator of the Fell Block We are focused on continued growth utilizing a disciplined capital structure we performed active exploration and development drilling that resulted in and a conservative financial philosophy. Due to the volatile nature of multiple oil and gas discoveries. commodity prices, fiscal discipline and a focus on disciplined capital structure • Colombia. In 2012, we acquired assets in Colombia at attractive prices, which are critical to our business. Our multi-country platform and asset portfolio gave us access to exploratory and productive acres with high prospects. is managed through our capital allocation methodology, which also allows In the Llanos Basin, we pioneered a new play type combining structural us to quickly adapt and grow. Under this methodology, each country, has and stratigraphic traps. As a result, in the Llanos 34 Block our average daily a local team running the business who recommends and advocates for the production has grown from 0 at the time of acquisition to more than 24,200 projects they want to move forward. The corporate team then ranks all of the bopd as of December 31, 2017. During 2016, following the successful projects based on economic, technical and strategic criteria, for the purpose appraisal drilling in the Tigana and Jacana oil fields, we materially increased of comparing projects. This also creates opportunities for improvements the field size. in the projects that can, in turn, improve their ranking. Finally, once the • Brazil. In 2014, we acquired Rio das Contas, which gave us a 10% working production and reserve growth targets are defined, the corporate team interest in the BCAM-40 Concession, including the shallow-depth offshore decides the amount of capital to be invested and allocates that capital to the Manati and Camarão Norte Fields in the Camamu-Almada Basin in the State highest value-adding projects. As an example, for the 2018 capital allocation of Bahia, which has consistently self-funded its operations. The Manati Field process, over 100 projects were presented with a final selection of 50 which has provided up to 4.5% of total gas produced in Brazil. comprise our 2018 work program, under the preliminary base capital program. • Argentina. During 2014, GeoPark and Pluspetrol were awarded two Additionally, given the inherent oil price volatility, we design our work exploration licenses in the Sierra del Nevado and Puelen Blocks as part of programs to be flexible, which means that they can be increased or decreased the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa depending on the oil price scenario. Mendocina de Energía S.A. (“EMESA”). In 2015, we acquired a 50% working interest in Block CN-V in Mendoza from Wintershall Energía S.A. On December We have historically benefited from access to debt and equity capital markets 18, 2017, we executed an asset purchase agreement (the “APA”) with and cash flows from operations, as well as other funding sources, which have Pluspetrol, a private oil and gas company with strong presence across Latin provided us with funds to finance our organic growth and the pursuit of America, to acquire a 100% working interest and operatorship of the Aguada potential new opportunities. Baguales, El Porvenir and Puesto Touquet blocks in Argentina. Closing of the transaction occurred on March 27, 2018. We generated US$142.2 million and US$82.9 million in cash from operations in • Peru. In December 2016, we expanded our footprint into Peru by acquiring the years ended December 31, 2017 and 2016, respectively, and had US$134.8 the Morona Block in a joint venture with Petroperú. The Morona Block million and US$73.6 million of cash and cash equivalents as of December 31, contains the Situche Central proven oil field, which we believe offers 2017 and 2016, respectively. extensive exploration potential with several potential high impact prospects GeoPark 67 As of December 31, 2017, we had US$426.2 million of total outstanding enable our technical team to focus its knowledge, skills and experience on indebtedness and over 99% of our debt had a maturity of 2024. finding and developing oil and gas fields. In February 2013, we issued US$300.0 million aggregate principal amount of In addition, we strive to provide a safe and motivating workplace for 7.50% senior secured notes due 2020 (the “Notes due 2020”). We repurchased employees in order to attract, protect, retain and train a quality team in the US$284.0 million aggregate principal amount of the outstanding Notes competitive marketplace for capable energy professionals. due 2020 in September 2017, and redeemed the remaining US$16.0 million aggregate principal amount outstanding in October 2017. Our CEO, Mr. James Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, In February 2014, we commenced trading on the NYSE and raised US$98 drilling and production operations, surface and pipeline construction, legal million (before underwriting commissions and expenses), including the over- and regulatory issues, crude oil marketing and transportation and capital allotment option granted to and exercised by the underwriters, through the raising for the industry. As of March 15, 2018, Mr. Park held 13.0% of our issuance of 13,999,700 common shares. outstanding common shares. In March 2014, we borrowed US$70.5 million pursuant to a five-year term Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the oil variable interest secured loan, secured by the benefits we receive under and gas business internationally and in North America since 1976. As of March the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to 15, 2018, Mr. O’Shaughnessy held 11.9% of our outstanding common shares. 6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das Our management and operating team has an average experience in the Contas acquisition. In March 2015, we reached an agreement to: (i) extend energy industry of more than 25 years in companies such as Chevron, ENAP, the principal payments that were due in 2015 (amounting to approximately Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our US$15 million), which were divided pro-rata during the remaining principal history, our management and operating team has had success in unlocking installments, starting in March 2016 and (ii) to increase the variable interest unexploited value from previously underdeveloped assets. rate equal to the 6-month LIBOR + 4.0%. The loan was fully repaid in September 2017. In addition, as of March 15, 2018, our executive directors, management and employees (excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy In December 2015, we entered into an offtake and prepayment agreement and Mr. James F. Park) owned 1.7% of our outstanding common shares, with Trafigura under which we sell and deliver a portion of our Colombian aligning their interests with those of our shareholders and helping retain crude oil production to Trafigura. The offtake agreement also provides us the talent we need to continue to support our business strategy. See “Item with prepayment of up to US$100 million, subject to applicable volumes 6. Directors, Senior Management and Employees—B. Compensation.” Our corresponding to the terms of the agreement, in the form of prepaid future oil founding shareholders are also involved in our daily operations and strategy. sales. Following subsequent amendments, the availability period under the prepayment agreement was extended until September 30, 2017. Long-term strategic partnerships and strong strategic relationships, such In September 2017, we issued US$425.0 million aggregate principal amount as with LGI, provide us with additional funding flexibility to pursue further of 6.50% senior secured notes due 2024 (the “Notes due 2024”). The Notes due acquisitions 2024 contain incurrence-based limitations on the amount of indebtedness We benefit from a number of strong partnerships and relationships. In we can incur See “Item 5. Operating and Financial Review and Prospects— March 2010, we entered into a framework agreement with LGI, a Korean Liquidity and capital resources—Indebtedness—Notes due 2024—Covenants.” conglomerate, to establish a strategic growth partnership to jointly acquire and invest in oil and natural gas projects throughout Latin America. In May Highly committed founding shareholders and technical and management 2011, our partnership with LGI was strengthened by LGI’s acquisition of a teams with proven industry expertise and technically-driven culture 10% equity interest in our existing Chilean operations. In October 2011, LGI Our founding shareholders, management and operating teams have acquired an additional 10% equity interest in GeoPark Chile and a 14% equity significant experience in the oil and gas industry and a proven technical and interest in GeoPark TdF, and agreed to provide additional financial support for commercial performance record in onshore fields, as well as complex projects the further development of the Tierra del Fuego Blocks. In December 2012, in Latin America and around the world, including expertise in identifying LGI acquired a 20% equity interest in our Colombian business. As of the date acquisition and expansion opportunities. Moreover, we differentiate of this annual report, we believe we are the only independent E&P company ourselves from other E&P companies through our technically-driven culture, in which LGI has equity investments in Latin America. See “—Significant which fosters innovation, creativity and timely execution. Our geoscientists, Agreements—Agreements with LGI” for additional information relating to geophysicists and engineers are pivotal to the success of our business these agreements. strategy, and we have created an environment and supplied the resources that 68 GeoPark 20-F In addition, IFC has been one of our shareholders since 2006, holding a 5.7% We intend to continue to focus on maintaining a risk-balanced portfolio equity interest in us as of December 31, 2017. In Chile, we believe we have of assets, combining cash flow-generating assets with upside potential strong long-term commercial relationships with Methanex and ENAP, and in opportunities, and on increasing production and reserves through finding, Colombia, we believe we have developed a strong relationship with Ecopetrol, developing and producing oil and gas reserves in the countries in which the Colombian state-owned oil and gas company. In Brazil, we believe we will we operate. In general, when we enter a new country we look for a mix of continue to derive benefit from the long-term relationship GeoPark Brazil has three elements: (i) producing fields, or existing discoveries with near-term with Petrobras. possibility of production, to generate cash flows; (ii) an inventory of adjacent low-risk prospects that can offer medium-term upside for steady growth; and On February 26, 2018, we announced the formation of a new long-term (iii) a periphery of higher-risk projects which have a potential to generate strategic partnership to jointly acquire, invest in, and create value from significant upside in the long run. upstream oil and gas projects with the objective of building a large-scale, economically-profitable and risk-balanced portfolio of assets and operations For example, in Colombia, we acquired three companies simultaneously across Latin America with the ONGC Videsh, the wholly-owned subsidiary and to pursue a risk-balanced approach: one company had mainly proven international arm of Oil and Natural Gas Corporation Limited (“ONGC”), India’s production and reserves to provide us with a steady cash flow base, and the national oil company. remaining had highly prospective exploration license blocks. Within four years of entering Colombia, we made multiple oil discoveries in block Llanos 34 that 2018 Strategy and Outlook allowed us to increase production and cash flows. Oil prices were volatile since the end of 2014. In preparation for continued volatility, we have developed multiple scenarios for our 2018 capital We believe this approach will allow us to sustain continuous and profitable expenditure program. growth and also participate in higher risk growth opportunities with upside Our preliminary base capital program for 2018 considers a reference oil price assumption of US$50-55 per barrel and calls for approximately US$100- Maintain financial strength potential. See “—Our operations.” 110 million to fund our exploration and development, which we intend to We seek to maintain a prudent and sustainable capital structure and a strong fund through cash flows from operations and cash-in-hand, to be allocated financial position to allow us to maximize the development of our assets approximately as follows: and capitalize on business opportunities as they arise. We intend to remain • Colombia: US$85-90 million. Focus on Llanos 34 Block to develop, appraise financially disciplined by limiting substantially all our debt incurrence to and further explore potential of the Tigana/Jacana oil play and target new identified projects with repayment sources. We expect to continue benefiting exploration prospects in Llanos 34 block. from diverse funding sources such as our partners and customers in addition • Chile: US$1-2 million. Focus on business optimization as well as to the international capital markets. environmental and unconventional studies in the Fell Block. • Brazil: US$3-4 million. Focus on exploration drilling in onshore blocks. Our cash flow generation is complemented by our financial hedging program. • Argentina: US$5-8 million. Focus on exploration drilling in CN-V, Sierra del During 2016 and 2017, we entered into derivative financial instruments to Nevado and Puelen blocks in the Neuquen Basin. manage our exposure to oil price risk. The purpose of our hedging strategy is • Peru: US$6-9 million. Focus on environmental impact studies and to establish minimum oil prices to secure stable cash flow and the execution preliminary engineering works and facilities in the Morona block. of our work program. For the period commencing January 2017 to December 2017, we hedged 12,000 bopd through a zero premium collar structure In addition, we have developed downside and upside work program scenarios with a minimum average Brent price of US$52 per barrel and a maximum based on different oil prices and project performance. The downside scenario average price of US$58 per barrel, representing 53% of our oil production work program considers a reference oil price assumption below US$50 for that period. For the period from January 2018 to March 2018, we have per barrel and consists of an alternative capital expenditure program of secured 13,000 bopd with a minimum average price of US$51.4 per barrel approximately US$50 million-US$90 million consisting mainly of certain and a maximum average price of US$52.8 per barrel via zero premium collars low risk and quick cash flow generating projects. The upside scenario work and three-way hedges (US$10/bbl wide put spread and call). For the period program considers a reference oil price assumption of US$60 per barrel from April 2018 to June 2018, we have secured 10,000 bopd with a minimum or higher and consists of an alternative capital expenditure program of average price of US$52.4 per barrel and a maximum average price of US$60.3 approximately US$120 million-US$150 million to be selected from identified per barrel via zero premium collars and three-way hedges (US$10/bbl wide projects designed to increase reserves and production. put spread and call). For the period commencing July 2018 to September 2018, we have secured 5,000 bopd with a minimum average price of US$53 Continue to grow a risk-balanced asset portfolio per barrel and a maximum average price of US$69 per barrel via zero premium three-way hedges (US$10/bbl wide put spread and call). GeoPark 69 We believe that by maintaining a disciplined capital structure and obligations and worked with our service partners to coordinate a smooth and conservative financial philosophy, including limiting our debt incurrence to efficient transition to a new plan. This has enabled us to control production specified projects with repayment sources and our use of financial hedges, we costs, as our average operating costs for the Llanos 34 Block were US$4.3 per are positioned to maintain sufficient liquidity and remain flexible in volatile boe for the year ended December 31, 2017.   commodity price environments. Our financial flexibility also gives us the ability to pursue new opportunities through future potential acquisitions. Maintain our commitment to environmental, safety and social responsibility A major component of our business strategy is our focus on and Pursue strategic acquisitions in Latin America commitment to our environmental and social responsibilities, in line with We have historically benefited from, and intend to continue to grow the IFC’s standards. We see this as a fundamental element of ensuring long through, strategic acquisitions in Latin America. These acquisitions term business initiatives. We are committed to minimizing the impact of have provided us with additional attractive platforms in the region. Our our projects on the environment and aim to create mutually beneficial Colombian acquisitions, for example, highlight our ability to identify relationships with the local communities in which we operate in order and execute on attractive growth opportunities, and we have grown to to enhance our ability to create sustainable value in our projects. These become the second largest private operator in Colombia. We acquired commitments are embodied in our in-house designed Environmental, Health, our interest in the Llanos 34 Block in the first quarter of 2012 for US$30 Safety and Security management program, which we refer to as “S.P.E.E.D.” million and have achieved 1P reserve growth corresponding to PV-10 of (Safety, Prosperity, Employees, Environment and Community Development). US$814 million as of December 31, 2017. Our enhanced regional portfolio, Our S.P.E.E.D. program was developed in accordance with several international primarily in investment-grade countries, and strong partnerships position quality standards, including ISO 14001 for environmental management issues, us as a regional consolidator. We intend to continue to grow through OHSAS 18001 for occupational health and safety management issues, ISO strategic acquisitions and potentially in other countries in Latin America, 26000 for social accountability and workers’ rights issues, and applicable World which we may consider from time to time. Our acquisition strategy is aimed Bank standards. See “—Health, safety and environmental matters.” at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside potential, keeping a balanced mix During 2016, we began the process of certifying ISO 14001 through programs of oil- and gas-producing assets (though we expect to remain weighted related to the efficient use of natural resources and compliance with towards oil) and focusing on both assets and corporate targets. environmental regulation. We have also provided training to our staff and the communities in which we operate with respect to these matters. Continue to foster a technically-driven culture and to capitalize on local knowledge In August 2017, we obtained the certification ISO 14001:2015 for our We intend to continue to deliberately and collectively pursue strategies Environmental Management Process (“SGA”) with the following scope: that maximize value. For this purpose, we intend to continue expanding “Design, construction, operation, maintenance, modernization and our technical teams and to foster a culture that rewards talent according dismantlement of GeoPark Colombia S.A.S.’s facilities, for the performance of to results. For example, we have been able to maintain the technical teams exploration and oil and gas production activities in the Llanos 34 and VIM-3 we inherited through our Colombian and Brazilian acquisitions. We believe blocks, with a commitment to continuously improve our processes.” local technical and professional knowledge is key to operational and long- term success and intend to continue to secure local talent as we grow our Our operations business in different locations. We have a well-balanced portfolio of assets that includes working and/or economic interests in 24 hydrocarbon blocks, 23 of which are onshore blocks, Maintain a high degree of operatorship to control production costs including 7 in production as of December 31, 2017, as well as in an additional As of the date of this annual report, we are and intend to continue to be shallow-offshore concession in Brazil that includes the Manati Field. In the operator of a majority of the blocks and concessions in which we have addition, we have one concession in Brazil, the PN-T-597 Block that is subject working interests. Operating the majority of our blocks and concessions gives to the entry into the concession agreement by the ANP. We also have the right us the flexibility to allocate our capital and resources opportunistically and to acquire and operate 85% of the Tiple Block in Colombia, subject to drilling efficiently within a diversified asset portfolio. We believe that this strategy has an exploratory well resulting in a commercial discovery. allowed, and will continue to allow, us to leverage our unique culture, focus on excellence and our talented technical, operating and management teams. Operations in Colombia For example, as commodity prices were projected to decline throughout 2015, Our Colombian assets currently give us access to more than 248,300 gross we announced in the first quarter of 2015 a decision to shift our development exploratory and productive acres across 6 blocks in what we believe to be one of plan primarily to our operations in the Llanos 34 Block to focus on the Llanos South America’s most attractive oil and gas geographies. Basin, which had demonstrated strong returns on capital. Our operating team reacted quickly to pivot our operations that were unburdened by drilling Since we entered Colombia in 2012, we have achieved consistent growth in 70 GeoPark 20-F our oil production and proved reserves in Colombia, mainly achieved through successful exploration and development activities we made at our operated CARIBBEAN SEA Llanos 34 Block, which as of December 31, 2017 accounts for 95% of our production and 99% of our proved reserves in Colombia. PANAMA The table below shows average production and proved oil reserves (derived from D&M Reserves Report) in Colombia for the years ended December 31, 2017, 2016 and 2015: VIM - 3 VENEZUELA Average net production (mboepd) Net proved reserves at year-end (mmbbl) 2017 21.8 65.5 2016 15.5 37.3 2015 13.2 30.4 PACIFIC OCEAN Yamu La Cuerva Abanico Llanos 32 Tiple Highlights of the year ended December 31, 2017 related to our operations in Colombia included: • Successful drilling campaign with 19 gross wells drilled and put into production in the Jacana and Tigana oil fields in the Llanos 34 Block; • Discovery of the new Chiricoca oil field, following the successful drilling and ECUADOR testing of the Chiricoca 1 exploration well; • Discovery of the new Jacamar oil field, located in a fault trend southeast of the Tigana/Jacana oil fields, following the successful drilling and testing of the Jacamar 1 exploration well. The well is producing from the Guadalupe formation. Oil shows during drilling and petrophysical analysis also indicate the potential Llanos 34 COLOMBIA PERU BRAZIL for hydrocarbon production in the shallower Mirador and the deeper Gacheta The Tiple Block is subject to drilling an exploratory well resulting in a formations; commercial discovery. • Discovery of the new Curucucu oil field, following the successful drilling and testing of the Curucucu 1 exploration well. To minimize surface construction The table summarizes information about the blocks in Colombia in which we costs and share production facilities, the Curucucu 1 exploration well was drilled have working interests as of and for the year ended December 31, 2017. from an existing well pad in the Jacamar oil field. The well was drilled with a horizontal extension of more than 9,000 feet, representing a record for the Llanos 34 block; • Average net production increased by 41%, to 21.8 mboepd in 2017 from 15.5 mboepd in 2016; • Proved oil reserves increased by 76% to 65.5 mmbbls at year-end 2017, from 37.3 mmbbls at year-end 2016 after producing 7.2 mmbbl; • Capital expenditures increased by 205% to US$80.0 million in 2017 from US$26.2 million in 2016; and • Maintenance of production and operating costs levels per barrel from US$5.4 in 2016 to US$5.6 in 2017. Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to an E&P Contract with the ANH, whereas “economic interests” are indirect participation interests in the net revenues from a given block based on bilateral agreements with the concessionaires. The map below shows the location of the blocks in Colombia in which we have working and/or economic interests. GeoPark 71 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 Exploration: 2017 82.2 45.0% Parex GeoPark 63.6 20,676 Llanos Exploitation: 2039 24.5 5.6 100.0% 89.5/ 100%(4) — — GeoPark GeoPark Llanos 32 57.0 12.5% Parex Parex VIM-3 46.9 100% — GeoPark 1.1 0.7 0.1 — 585 Llanos Exploitation: 2038 Exploration: 2014 267 Llanos Exploration: 2013 Production: 2036 Exploration: 2015 209 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 of the Gachetá formation. The main reservoirs of the basin are represented by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous in such block. LGI currently has a 20% direct equity interest in our Colombian sequence, several sandstones are also considered to have good reservoirs. operations through GeoPark Colombia SAS. However, we can earn back up to 12% additional equity interests in GeoPark Colombia depending on Llanos 34 Block . We are the operator of, and have a 45% working interest in, the the success of our Colombian operations. See “—Significant Agreements— Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq. km). Agreements with LGI—LGI Colombia Agreements.” (2) Partners with working interests. (3) As of December 31, 2017. (4) Although we are the sole title holder of the working interest in the Yamú Block, other parties have been granted economic interests in fields in this We acquired an interest in and took operatorship of the block in the first quarter of 2012, which at the time had no production, reserves or wells drilled on it, and with 210 sq. km of existing 3D seismic data on which our team had mapped multiple exploration prospects. From 2012 to 2016 we engaged in exploration and development activities that resulted in multiple new oil fields discovered block. Taking those other parties’ interests into account, we have a 89.5% and increased production and proved reserves year by year until 2016. Average interest in the Carupana Field and a 100% interest in the Yamú and Potrillo net production in 2016 was 14,890 bopd and net reserves of 37.1 mmbbl. The Fields, both located in the Yamú Block. remaining commitment amounts to US$6.3 million at our working interest. As of the date of this Annual Report, we are awaiting the ANH’s approval of US$3.6 The table summarizes information about the blocks in Colombia in which we million related to one well already drilled that was presented as fulfilment of have economic interests as of and for the year ended December 31, 2017. the commitment to be performed before September 2019. Gross acres (thousand acres) 32.1 Economic interest(1) 10% Block Abanico Production Our operations.” We operate in the block pursuant to an E&P Contract with the Operator (boepd) Basin ANH. See “—Significant Agreements—Colombia—E&P Contracts—Llanos 34 Our partner in the Llanos 34 Block is Parex, which has a 55% interest. See “— Pacific 50 Magdalena Block E&P Contract.” (1) Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant to a joint operating agreement. La Cuerva Block. We are the operator of, and have a 100% working interest in, the La Cuerva Block, which covers approximately 24,500 gross acres (99.1 sq. km). Due to the impact of low oil prices, we temporarily ceased operations in Eastern Llanos Basin: (Llanos 34, La Cuerva, Yamú, Llanos 32, Llanos 17, Jagüeyes some fields during 2015 and 2016. Average net oil production in 2017 was 585 3432A, Abanico, and VIM-3 Blocks) bopd. As of February 28, 2018, 22 wells were productive. We operate in the block pursuant to an E&P Contract with the ANH. The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region of Colombia. Two giant fields (Caño Limón and Castilla), three major fields Yamú Block . We are the operator of, and have a 100% working interest in, (Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had the Yamú Block, which covers approximately 5,588 gross acres (22.6 sq. km). been discovered. The source rock for the basin is located beneath the east flank Economic rights to certain fields in the Yamú Block have been granted to other of the Eastern Cordillera, as a mixed marine-continental shaly basinal facies parties. In May 2013, we successfully drilled and completed the Potrillo 1 well. 72 GeoPark 20-F For the year ended December 31, 2017, our average net production was 267 Operations in Chile bopd. We resumed operations in this block in March 2017. 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 Llanos 17 Block . We had a 40% working interest in the Llanos 17 Block, which Magallanes Basin, with existing reserves, production and cash flows. covered approximately 108,800 gross acres (440 sq. km) pursuant to an E&P Contract with the ANH. In October 2017, ANH confirmed that the contract was Our Chilean blocks are located in the provinces of Ultima Esperanza, liquidated. Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil- and gas-producing area. As of December 31, 2017, the Magallanes Basin Llanos 32 Block . We have a 12.5% working interest in the Llanos 32 Block, as a accounted for all of Chile’s oil and gas production. Although this basin has result of our acquisition of an additional 2.5% interest on August 22, 2017. The been in production for over 60 years, we believe that it remains relatively Llanos 32 Block covers approximately 57,000 gross acres (230.7 sq. km). Parex underdeveloped. is the operator of this block, and has a 70% working interest. Pluspetrol has a 20% working interest. Since 2015, the operator focused on the commissioning Substantial technical data (seismic, geological, drilling and production of a gas facility on this block to produce natural gas and light crude oil from information), developed by us and by ENAP, provides an informed base for the Une formation and to facilitate shipment of processed gas south to new hydrocarbon exploration and development. Shut-in and abandoned the adjacent Llanos 34 Block. For the year ended December 31, 2017, our fields may also have the potential to be put back in production by average net production in the Llanos 32 Block was 209 bopd. The remaining constructing new pipelines and plants. Our geophysical analyses suggest commitment related to this block is to drill one exploratory well before August additional development potential in known fields and exploration potential 2018 amounting to US$0.6 million at our working interest. in undrilled prospects and plays, including opportunities in the Springhill, Tertiary, Tobífera and Estratos con Favrella formations. The Springhill Jagüeyes 3432A Block . We had a 5% working interest in the Jagüeyes 3432A formation has historically been the source of production in the Fell Block, Block, which covered approximately 61,000 acres (247 sq. km). In December though the Estratos con Favrella shale formation is the principal source rock 2017, ANH confirmed that the contract was liquidated. of the Magallanes Basin, and we believe it contains unconventional resource Abanico Block . In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. potential. entered into the Abanico Block association contract. Pacific is the operator of, Highlights of the year ended December 31, 2017 related to our operations in and has a 100% working interest in, the Abanico Block, which covers an area of Chile included: approximately 32,100 gross acres. We do not maintain a direct working interest in • Average net oil and gas production declined to 2,885 boepd in 2017 from the Abanico Block, but rather have a 10% economic interest in the net revenues 3,874 boepd in 2016; from the block pursuant to a joint operating agreement initially entered into with • Proved oil and gas reserves decreased by 40% to 7.5 mmboe at year-end Kappa Resources Colombia Limited (now Pacific, who subsequently assigned its 2017, from 12.6 mmboe at year-end 2016 after producing 1.0 mmboe; participation interest to Cespa de Colombia S.A., who then assigned the interest • Capital expenditures were increased by 31% to US$10.2 million in 2017 to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A. from US$7.8 million in 2016; and • Drilling and completion of the Uaken 1 exploration well to a total depth of VIM-3 Block. On July 23, 2014 we were awarded a new exploratory license 3,658 feet. The Uaken gas field discovery in the shallower El Salto formation during the 2014 Colombia Bidding Round, carried out by the ANH. We are provides additional low-cost production and creates a new gas play across entitled to operate the block, in which we have a 100% working interest. the Fell block that can be tested in identified leads and prospects. In addition, The VIM-3 Block is located in the Lower Magdalena Basin, covering an area there are multiple wells in already discovered oil and gas fields within the Fell of approximately 225,000 acres. Our winning bid consisted of committing to block that can be re-entered to test this formation. a Royalty X Factor of 3% and a minimum investment program of 200 sq. km • Successful cost reduction efforts impacting production and operating costs of 2D seismic data acquisition and drilling one exploratory well, with a total that represented a 5% reduction, to US$21.0 million in 2017 as compared to estimated investment of US$22.3 million during the initial exploratory period US$22.2 million in 2016. ending February 2019. On June 21, 2017, ANH approved our relinquishment of 79.15% of the VIM 3 Block area. The remaining area will cover 46,881 acres and the commitments described above are not affected. GeoPark 73 The map below shows the location of the blocks in Chile in which we have working interests. CHILE ARGENTINA Tranquilo Fell Isla Norte Campanario Flamenco 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, 2017. Block Fell Tranquilo Isla Norte 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 7.3 2,835 Magallanes Exploitation: 2032 92.4 50% Pluspetrol GeoPark 97.7 60%(4) ENAP GeoPark Campanario 144.2 50%(4) ENAP GeoPark Flamenco 105.9 50%(4) ENAP GeoPark — — — 0.2 — Magallanes Exploitation: 2043 — Magallanes — Magallanes Exploration: 2021 Exploitation: 2044 Exploration: 2021 Exploitation: 2045 Exploration: 2021 50 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. LGI has a 20% direct equity interest in our (3) As of December 31, 2017. (4) LGI has a 14% direct equity interest in our Tierra del Fuego operations through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for Chilean operations through GeoPark Chile. See “—Significant Agreements— a total effective equity interest of 31.2% in our Tierra del Fuego operations. Agreements with LGI—LGI Chile Shareholders’ Agreements.” (2) Partners with working interests. See “—Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)” and “—Significant Agreements—Agreements with LGI—LGI Chile Shareholders’ Agreements.” 74 GeoPark 20-F Fell Block In 2006, we became the operator and 100% interest owner of the Fell Block. The Fell Block also contains the Estratos con Favrella shale reservoir, which we When we first acquired an interest in the Fell Block in 2002, it had no material believe represents a high-potential, unconventional resource play for shale oil, oil and gas production. Since then, we have completed more than 1,100 sq. as a broad area within Fell Block (1,000 sq. km) which appears to be in the oil km of 3D seismic surveys and drilled 117 exploration and development wells. window for this play. In the year ended December 31, 2017, we produced an average of 2,835 boepd, in the Fell Block, consisting of 54% oil. In February 2018, Methanex announced the reopening of their second plant in Punta Arenas, which is estimated to reopen by the end of the third quarter The Fell Block has an area of approximately 368,000 gross acres (1,488 sq. of 2018. km) and its center is located approximately 140 km northeast of the city of Punta Arenas. It is bordered on the north by the international border between Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks) Argentina and Chile and on the south by the Magellan Strait. In the first and second quarters of 2012, we entered into three CEOPs with ENAP and Chile granting us working interests in the Isla Norte, Campanario From 2006 through August 2011, we successfully explored and developed and Flamenco Blocks, located in the center-north of the Tierra del Fuego the Fell Block, which allowed us to transition approximately 84% of the Fell province of Chile. We are the operator of all three of these blocks, with Block’s area from an exploration phase into an exploitation phase, which we working interests of 60%, 50% and 50%, respectively. We believe that these expect will last through 2032. During the exploration phase, we exceeded the three blocks, which collectively cover 347,700 gross acres (1,407 sq. km) and minimum work and investment commitment required under the Fell Block are geologically contiguous to the Fell Block, represent strategic acreage CEOP by more than 75 times. There are no minimum work and investment with resource potential. We have committed to paying 100% of the required commitments under the Fell Block CEOP associated with the exploitation minimum investment under the CEOPs covering these blocks, in an aggregate phase. amount of US$101.4 million through the end of the first exploratory periods for these blocks, which occurred in November 2015 for the Flamenco Block, The Fell Block is located in the north-eastern part of the Magallanes Basin. in May 2017 for the Isla Norte Block and in July 2017 for the Campanario The principal producing reservoir is composed of sandstones in the Springhill Block, which includes our covering of ENAP’s investment commitment formation, at depths of 2,200 to 3,500 meters. Additional reservoirs have corresponding to its working interest in the blocks. Under Article 5.3 of CEOP, been discovered and put into production in the Fell Block—namely, Tobífera at the end of the first exploration period, the contractor defines the area to formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper be retained and we were required to return to the state at least 25% of the Tertiary and Upper Cretaceous sandstones, at depths of 700 to 2,000 meters. original area of the contract. The first exploration period of Isla Norte and Our geosciences team identified and developed an attractive inventory of Campanario Blocks ended in 2017, at which point we relinquished 80.6 gross prospects and drilling opportunities for both exploration and development acres (583 sq. km). in the Fell Block. Previous oil discoveries in the Konawentru, Yagán, Yagán Norte, Copihue and Guanaco fields have opened up new oil and gas potential Isla Norte Block . We are the operator of, and have a 60% working interest in in the Fell Block. An important discovery during 2011 was the Konawentru partnership with ENAP in the Isla Norte Block, which covers approximately 1 well, which we initially tested to have in excess of 2,000 bopd from the 97,650 gross acres (395 sq. km). As of March 2018, we had completed 100% of Tobífera formation, and which has opened up additional potentially attractive the committed 350 sq. km of 3D seismic surveys and drilled one exploratory opportunities (workovers, well-deepening’s and new exploration and well, which represents the first oil discovery within the block. As of the date development wells) in the Tobífera formation throughout the Fell Block. of this annual report, outstanding investment commitments of US$2.9 million From 2012 to 2014, we focused our exploration and development plan in the related to this block correspond to two exploratory wells to be executed Tobífera formation by drilling wells in Konawentru, Yagán and Yagán Norte before May 7, 2019. fields, as well as deepening existing wells in Ovejero and Molino. Exploration efforts in 2014 resulted in the discoveries of the Ache gas field and the Loij oil Campanario Block . We are the operator of, and have a 50% working interest field. in, the Campanario Block, in partnership with ENAP. The block covers approximately 144,150 gross acres (583 sq. km). As of March 31, 2018, we During 2015, although there were no wells drilled, we put into production a had completed 100% of the committed 578 sq. km of 3D seismic surveys and new gas field, Ache, that was discovered in 2014. During 2016, we successfully have also drilled five exploratory wells, including the Primavera Sur 1 well that drilled the Pampa Larga 16 well and continued focusing on maintaining marks the first discovery of an oil field on the Campanario Block in addition production levels and reducing production and operating costs. During 2017, to one development well. As of the date of this annual report, outstanding we drilled three wells; two of them were put into production (Kimiriaike 4 investment commitments of US$4.8 million related to this block correspond to and Uaken X-1) and the remaining well (Ache-3) is still under evaluation. three exploratory wells to be executed before July 10, 2019. In addition, we continued to focus on maintaining production levels and reducing production and operating costs. GeoPark 75 Flamenco Block . We are the operator of, and have a 50% working interest in, Operations in Brazil the Flamenco Block, in partnership with ENAP. The block covers approximately Our Brazilian assets currently give us access to 84,300 of gross exploratory 105,900 gross acres (428 sq. km). In June 2013, we discovered a new oil and gas and productive acres across 9 blocks (8 exploratory blocks and the BCAM-40 field in the block following the successful testing of the Chercán 1 well, the first Concession, which is in production phase) in an attractive oil and gas geography. well drilled by us in Tierra del Fuego. As of March 31, 2018, we had completed Highlights of the year ended December 31, 2017 related to our operations in 100% of the committed 570 sq. km of 3D seismic surveys. We have also Brazil included: committed to drilling ten wells during the first exploration period under the • Average net oil and gas production of 2,910 boepd (99% gas) in the year CEOP governing the Flamenco Block. In the year ended December 31, 2017, ended December 31, 2017, as compared to 2,930 boepd in 2016; we produced an average of 50 boepd in the Flamenco Block. • Capital expenditures remained at US$3.6 million in 2017; On June 30, 2017, the Chilean Ministry accepted our proposal to extend the total depth of 7,654 feet. Main targets, Sergi and Agua Grande formations, were second exploratory period for an additional period of 18 months. As of the found to be water bearing with reservoir thicknesses of 36 feet and 46 feet, date of this annual report, outstanding investment commitments related respectively. In addition, 47 feet of reservoir with oil traces were encountered in to this block correspond to 1 exploratory well until May 7, 2019 for US$2.1 a secondary target, in the Gomo formation. Following an in-depth geological million, to be assumed 100% by us. and geophysical analysis, a decision was made to plug and abandon the well • Praia do Espelho exploration prospect in Reconcavo Basin was drilled to a Otway and Tranquilo Blocks In relation to the Otway Block, we have informed the Ministry of Energy during the second quarter of 2017; and • A new block awarded in Round 14 (POT-T-785 Block). the termination of the CEOP due to the fact that the two provisional areas The map below shows the location of our concessions in Brazil in which we of Tatiana and Cabo Negro have expired in September and October 2017, have a current or future working interest, including the BCAM-40 Concession respectively. There were no pending obligations at the end of the CEOP. and the concessions from bidding rounds 11, 12, 13 and 14. We are the operator of the Tranquilo Block. In the Tranquilo Block, as of December 31, 2017, we had a 50% working interest alongside our partner Pluspetrol. In the 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 BRAZIL 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. 76 GeoPark 20-F POT - T 747 POT-T-785 POT - T 882 PN - T 597(1) REC - T 94 REC - T 93 REC- T 128 POT - T 619 SEAL - T 268 BCAM - 40 (Manati) PARAGUAY ARGENTINA (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. Risk factors—Risks relating to our business—The PN-T-597 Concession Agreement in Brazil may not close.” The following table sets forth information as of December 31, 2017 on our concessions in Brazil in which we have a current or future working interest, including the BCAM-40 Concession and the concessions from bidding rounds 11, 12, 13 and 14. Gross acres (thousand acres) Working interest(1) 7.7 100% 100% 100% 100% 100% 7.9 188.7 7.8 7.8 7.6 — — — — — GeoPark GeoPark GeoPark GeoPark GeoPark 70% Geosol GeoPark 6.9 100%(5) 7.9 100%(5) 7.9 100%(5) — — — GeoPark GeoPark GeoPark Petrobras; Concession REC-T 94 POT-T 619 PN-T-597(4) SEAL-T-268 REC-T-93 REC-T-128 POT-T-747 POT-T-882 POT-T-785 BCAM-40 Partners Operator Net proved reserves (mmboe)(3) Production (boepd) Basin Concession expiration year Exploration: 2020 — — — — — — — — — — Recôncavo Exploitation: 2047 — — — Potiguar Parnaíba Sergipe Alagoas Exploration: 2018 Exploitation: 2045 — Exploration: 2020 Exploitation: 2047 Exploration: 2018 — Recôncavo Exploitation: 2045 Exploration: 2018 — Recôncavo Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Potiguar Camamu- Exploration: 2023 Exploitation: 2050 Exploitation: 2029(2) - 2034(3) — — — 22.8 10% QGEP; Brasoil Petrobras 4.0 2,910 Almada (1) Working interest corresponds to the working interests held by our respective subsidiaries, net of any working interests held by other parties in and 45% working interests, respectively. Petrobras operates the BCAM-40 Concession pursuant to a concession agreement with the ANP, executed on such concession. See “Item 3. Key Information—D. Risk factors—Risks relating August 6, 1998. See “—Significant Agreements—Brazil—Overview of concession to our business—The PN-T-597 Concession Agreement in Brazil may not close.” (2) Corresponds to Manati Field. (3) Corresponds to Camarão Norte Field. (4) 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 agreements—BCAM-40 Concession Agreement.” In September 2009, Petrobras announced the relinquishment of BCAM-40’s exploration area within the concession to the ANP, except for the Manati Field and the Camarão Norte Field. The Manati Field is located 65 km south of Salvador, offshore at a 35 meter this annual report, confirmation remains subject to final signing and local water depth. The field was discovered in October 2000, and, in 2002, Petrobras authority approval. See “Item 3. Key Information—D. Risk factors—Risks declared the field commercially viable. Production began in January 2007. relating to our business—The PN-T-597 Concession Agreement in Brazil may As of December 31, 2017, 11 wells had been drilled in the Manati Field, not close.” (5) A 30% working interest of proposed partners is subject to ANP approval. BCAM-40 Concession six 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 As a result of the Rio das Contas acquisition, we have a 10% working interest is sold to Petrobras up to a maximum volume as determined in the existing in the BCAM-40 Concession, which includes interests in the Manati Field and Petrobras Gas Sales Agreement (as defined below). In July 2015, we signed an the Camarão Norte Field, and which is located in the Camamu-Almada Basin. amendment to the existing Gas Sales Agreement with Petrobras that covers Petrobras is the operator, and has a 35% working interest in, the BCAM-40 100% of the remaining gas reserves of the Manati Field. Concession, which covers approximately 22,784 gross acres (92.2 sq. km). In addition to us, Petrobras’ partners in the block are Brasoil and QGEP, with 10% Also in 2015, in order to improve the field gas recovery and production, GeoPark 77 Manatì’s consortium built an onshore compression plant that started Round 12 Concessions operating in August 2015. The compression plant involved capital In November 2013, in the 12th Bid Round, the ANP awarded us two new expenditures of approximately US$3.7 million at our working interest and concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of allowed us to classify all existing proved undeveloped reserves as proved Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in developed as of December 31, 2016. the State of Alagoas. Some environmental licenses related to operation of the Manati Field For more information, see “Item 3. Key information—D. Risk factors—Risks production system and natural gas pipeline are expired. However, the operator relating to our business—The PN-T-597 Concession Agreement in Brazil may submitted, in a timely manner, the request for renewal of those licenses and as not close.” such this operation is not in default as long as the regulator does not state its final position on the renewal. The Camarão Norte Field is in the development PN-T-597 Concession phase and is not yet subject to the environmental licensing requirement. The Parnaiba Basin, which covers an area of approximately 148 million Round 11 Concessions During ANP’s 11th Bid Round, held in May 2013, we were awarded 7 gross acres (600,000 sq. km), is a basin with large underexplored areas. As of December 31, 2017, the basin had two fields in production in the basin. 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$2.3 million, at the December 31, 2017 exchange rate of R$3.3 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$5.3 million, political and economic circumstances in the countries in which we operate at the December 31, 2017 exchange rate of R$3.3 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$0.5 million, at the December 31, 2017 exchange rate of R$3.3 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$0.7 million at the December 31, 2017 exchange rate of remaining committed work program that amounts to US$ 0.2 million. R$3.3 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 78 GeoPark 20-F POT-T-747 and POT-T-882 The POT-T-747 and POT-T-882 blocks are located in the Potiguar Basin and The map below shows the location of the Morona Block in Peru. encompass an area of 14,829 acres (60 square km). Total commitment to the ANP was R$8.5 million (approximately US$2.6 million, at the December 31, 2017 exchange rate of R$3.3 to US$1.00) during the first exploratory period and is equivalent to acquiring 70 km of 2D seismic, and drilling one well. During 2017 3D seismic was reprocessed and a well was drilled in the POT-T-747 block during 2018 and was abandoned. The estimated remaining commitment amounts to US$0.2 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$3.2 million at the December 31, 2017 exchange rate of R$3.3 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 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 2017, 3D reprocessing was performed in the REC-T-128 block. The estimated remaining commitment amounts to US$2.9 million. 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$0.4 million, at the December 31, 2017 exchange rate of R$3.3 to US$1.00) during the first exploratory period and is equivalent to acquiring 4 km2 of 3D seismic, and performing geochemical analysis. 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. The Morona Block has DeGolyer and MacNaughton certified net proved reserves of 18.7 mmboe as of December 31, 2017, composed of 100% oil. ECUA DOR COLOMBIA Morona BRAZIL PERU PACIFIC OCEAN BOLIVIA CHILE GeoPark 79 The table below summarizes information about the block in Peru. Block Morona Gross acres (thousand acres) 1,881 Working interest(1) 75% Operator GeoPark Net proved reserves (mmboe)(2) 18.7 Production (boepd) Basin — Marañon Expiration concession year Exploitation: 2038 (3) (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 of our investments in the block through agreed terms in the Petroperu SPA. 2020. We expect these expenditures to be substantially reimbursed by Petroperu from revenues associated to future sales. See “Item 4. Information on the Company—B. Business Overview—Our In accordance with the agreement between us and Petroperu, commitments operations—Operations in Peru—Morona Block.” (2) Certified by DeGolyer and MacNaughton as of December 31, 2017. (3) The concession will expire twenty (20) years after EIA approval. assumed by GeoPark are subject to certain economical and technical conditions being met. Morona Block The third stage, which will be initiated once production has been established, is expected to focus on carrying out the full development of the Situche The Morona Block covers an area of approximately 1,881 thousand gross acres Central field, including transportation infrastructure. (7,600 sq. km). More than 1 billion barrels of oil have been produced from the surrounding blocks in the Marañon Basin. The exploratory program entails drilling one exploratory well. Exploratory program capital expenditures will be borne exclusively by us. Expected On October 1, 2014, we entered into an agreement to acquire a 75% working capital expenditures in 2018 for the Morona Block are mainly related to facility interest in the Morona Block in Northern Peru. As stated above, this agreement maintenance and environmental and engineering studies in order to get the includes a work program to be executed by us. This program includes 3 approval of the Development Environmental Impact Study by the end of the phases, and we may decide whether to continue or not at the end of each year. phase. On December 1, 2016, through Supreme Decree N° 031-2016-MEN, the Peruvian government approved the amendment to the License Contract Initially we will hold a 75% working interest in the block. However, according of Morona Block appointing GeoPark as operator and holder of 75% of the to the terms of the agreement, Petroperu has the right to increase its working License-Contract. interest in the block by up to 50%, subject to the recovery of our investments in the block by certain agreed factors. The Morona Block contains the Situche Central oil field, which has been See “Item 3. Key Information—D. Risk factors—Risks relating to our business— delineated by two wells (with short term tests of approximately 2,400 and “Our inability to access needed equipment and infrastructure in a timely 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the manner may hinder our access to oil and natural gas markets and generate Situche Central field, the Morona Block has a large exploration potential significant incremental costs or delays in our oil and natural gas production” with several high impact prospects and plays. The Morona Block includes and “—We may suffer delays or incremental costs due to difficulties in geophysical surveys of 2,783 km (2D seismic) and 465 sq. km (3D seismic), and negotiations with landowners and local communities, including native an operating field camp and logistics infrastructure. The area has undergone communities, where our reserves are located.” oil and gas exploration activities for the past 40 years, and there exist ongoing association agreements and cooperation projects with the local communities. The expected work program and development plan for the Situche Central oil field is to be completed in three stages. The goal of the initial two stages is to start production from the two wells 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 by the first half of 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, 80 GeoPark 20-F Operations in Argentina The map below shows the location of the blocks in Argentina in which we have working interests as of December 31, 2017. BOLIVIA PARAGUAY ARGENTINA BRAZIL URUGUAY Sierra del Nevado Puelen CV-V CHILE The table below summarizes information about the blocks in Argentina in which we have working interests as of December 31, 2017. Block Puelen Sierra del Nevado CN-V Gross acres (thousand acres) 305.4 1,433.2 117.0 Working interest(1) 18% 18% 50% Operator Pluspetrol Pluspetrol GeoPark Net proved reserves (mmboe)(2) — — — Production (boepd) — — 4 Basin Neuquén Neuquén Neuquén Expiration concession year Exploration: 2020 Exploration: 2020 Exploration: 2018 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. (2) As of December 31, 2017. GeoPark 81 Highlights of the year ended December 31, 2017 related to our operations in another exploratory well before the end of the second exploration period, for Argentina included: a total of US$10 million. • Discovery of the Rio Grande Oeste oil field in CN-V block following the successful drilling and testing of the exploratory well Rio Grande Oeste 1; and The CN-V Block covers an area of approximately 117,000 acres and is located in • Execution of an asset purchase agreement with Pluspetrol to acquire 100% the Neuquén Basin in southern Argentina. The block has 3D seismic coverage working interest and operatorship of the Aguada Baguales, El Porvenir and of 180 sq. km and is adjacent to the producing Loma Alta Sur oil field, a region Puesto Touquet blocks (“the blocks”) for a total consideration of US$52 million. and play-type well known to our team. The block includes upside potential in The blocks include: the developing Vaca Muerta unconventional play. - estimated oil and gas production of approximately 2,700 boepd - 70% light oil and 30% gas; During 2017, we drilled the first exploratory well, Rio Grande Oeste 1, which - 137,000 acres in the Neuquen Basin; and resulted in the discovery of Rio Grande Oeste oil field. These investments - production facilities, including hydrocarbons treatment, storage, represent the fulfilment of 50% of the commitment for the block. and delivery infrastructure. Del Mosquito Block 2014 Mendoza Bidding Round On April 2016 the concession of the Del Mosquito expired and we relinquished On August 20, 2014, the consortium of Pluspetrol and us was awarded two the entire remaining acreage to provincial authorities. As of the date of this exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of annual report, the approval of the abandonment plan for remediation and the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa restoration of the block is still pending. Mendocina de Energía S.A. (“EMESA”). The consortium consists of Pluspetrol (operator with a 72% working Overview interest), EMESA (non-operator with a 10% working interest) and us (non- We have achieved consistent growth in oil and gas reserves from our operator with an 18% working interest). In accordance with the terms of investment activities since 2007, when we began production in the Fell Block, the bidding, all of the expenditures related to EMESA’s working interest will followed by successful acquisition, exploration and development activities in be carried by Pluspetrol and us proportionately to our respective working other countries in which we have a presence, including Colombia, Brazil and Oil and natural gas reserves and production interests, and will be recovered through EMESA’s participation in future Peru. potential production. Our reserves Puelen Block : The Puelen Block covers an area of approximately 305.4 The following table sets forth our oil and natural gas net proved reserves as of thousand gross acres, and is located in the Neuquén Basin in southern December 31, 2016, which is based on the D&M Reserves Report. Argentina. Sierra del Nevado Block : The Sierra del Nevado Block covers an area of As of December 31, 2017 approximately 1,433.2 thousand gross acres, and is located in the Neuquén Basin in southern Argentina. Net proved reserves We have committed to a minimum aggregate investment of US$6.2 million for Net proved developed our working interest, which includes the work program commitment on both Colombia blocks during the first three years of the exploratory period. As of December 31, 2017, the remaining commitments in these blocks for the first exploratory period amount to US$1.2 million at our working interest. Chile Peru Brazil Oil (mmbbl) 21.1 0.7 9.5 0.1 CN-V Block Farm-in Agreement Total net proved developed 31.4 Net proved undeveloped On July 22, 2015, we signed a farm-in agreement with Wintershall for the Colombia CN-V Block in Argentina, which complements our existing acreage in the basin. Wintershall is Germany’s largest oil and gas producer and a subsidiary of BASF Group. We will operate during the exploratory phase and receive a 50% working interest in the CN-V Block in exchange for having drilled one exploratory well before the end of the second quarter of 2017 and to drill Chile Peru Brazil Total net proved undeveloped (2) Total net proved 44.4 3.4 9.2 - Total net Natural proved gas (bcf ) reserves (mmboe)(1) - 8.7 - 23.8 32.5 - 11.3 - - 21.1 2.2 9.5 4.0 36.8 44.4 5.3 9.2 - % Oil 100% 32% 100% 3% 85% 100% 64% 100% - 57.0 11.3 58.9 97% 82 GeoPark 20-F (Colombia, Chile, Peru, Brazil) 88.4 43.8 95.7 92% (1) We calculate one barrel of oil equivalent as six mcf of natural gas. (2) We plan to put 100% of our reported 2017 year-end proved undeveloped reserves into production through activities to be implemented within five years of initial disclosure. Throughout each fiscal year, our technical team meets with Independent Qualified Reserves Engineers, who are provided with full access to complete and accurate information pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally- generated reserves estimates is beneficial in ensuring that interpretations Changes for the year ended December 31, 2017 not including annual and judgments are reasonable and that the estimates are free of preparer and production, include (i) an increase of 3.8 mmboe resulting from better than management bias. expected performance from existing wells, from the Tigana and Jacana fields in the Llanos 34 Block; (ii) an increase of 3.0 mmboe resulting from Recognizing that reserves estimates are based on interpretations and the impact of higher average prices; (iii) an increase of 1.5 mmboe due to judgments, differences between the proved reserves estimates prepared by a better performance in the proved reserves in Chile and (iv) an increase of us and those prepared by an Independent Qualified Reserves Engineer of 29.0 mmboe due to extensions and discoveries from the Chiricoca, Jacamar, 10% or less, in aggregate, are considered to be within the range of reasonable and Curucucu fields in the Llanos 34 Block and the Tigana and Jacana field differences. Differences greater than 10% must be resolved in the technical extensions in the Llanos 34 Block. Such increase was partially offset by a meetings. Once differences are resolved, the independent Qualified Reserves decrease in reserves mainly related to a change in a previously adopted Engineer sends a preliminary copy of the reserves report to be reviewed by development plan and unsuccessful proved undeveloped execution in the Fell the Technical Committee and Directors of each country. A final copy of the Block in Chile, resulting in a 6.0 mmboe decrease. Reserves Report is sent by the Independent Qualified Reserve Engineer to be During the year ended December 31, 2017, we had 12.5 mmboe of our “Item 6. Directors, Senior Management and Employees—C. Board Practices— approved and signed by the Technical Committee and our CEO and CFO. See proved undeveloped reserves from December 31, 2016 converted to proved Committees of our board of directors.” developed reserves due to development drilling in the Jacana and Tigana oil fields in the Llanos 34 Block. For further information relating to the Independent reserves engineers reconciliation of our net proved reserves for the years ended December 31, Reserves estimates as of December 31, 2017 for Colombia, Chile, Brazil and 2017, 2016 and 2015, please see Table 5 included in Note 37 (unaudited) to our Peru included elsewhere in this annual report are based on the D&M Reserves Consolidated Financial Statements. Report, dated February 15, 2018 and effective as of December 31, 2017. The D&M Reserves Report, a copy of which has been filed as an exhibit to Internal controls over reserves estimation process this annual report, was prepared in accordance with SEC rules, regulations, We maintain an internal staff of petroleum engineers and geosciences definitions and guidelines at our request in order to estimate reserves and for professionals who work closely with our independent reserves engineers the areas and period indicated therein. to ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimation process and who have DeGolyer and MacNaughton, a Delaware corporation with offices in Dallas, knowledge of the specific properties under evaluation. Our Director of Houston, Moscow, Algiers, Astana and Buenos Aires has been providing Development, Carlos Alberto Murut, is primarily responsible for overseeing consulting services to the oil and gas industry since 1936. The firm has the preparation of our reserves estimates and for the internal control over more than 200 professionals, including engineers, geologists, geophysicists, our reserves estimation. He has more than 30 years of industry experience petrophysicists and economists that are engaged in the appraisal of oil and as an E&P geologist, with broad experience in reserves assessment, field gas properties, the evaluation of hydrocarbon and other mineral prospects, development, exploration portfolio generation and management and basin evaluations, comprehensive field studies and equity studies related to acquisition and divestiture opportunities evaluation. See “Item 6. Directors, the domestic and international energy industry. DeGolyer and MacNaughton Senior Management and Employees—A. Directors and senior management.” restricts its activities exclusively to consultation and does not accept In order to ensure the quality and consistency of our reserves estimates and properties, or securities or notes of its clients. The firm subscribes to a code reserves disclosures, we maintain and comply with a reserves process that of professional conduct, and its employees actively support their related satisfies the following key control objectives: technical and professional societies. The firm is a Texas Registered Engineering contingency fees, nor does it own operating interests in any oil, gas or mineral • estimates are prepared using generally accepted practices and Firm. methodologies; • estimates are prepared objectively and free of bias; The D&M Reserves Report covered 100% of our total reserves. In • estimates and changes therein are prepared on a timely basis; connection with the preparation of the D&M Reserves Report, DeGolyer • estimates and changes therein are properly supported and approved; and and MacNaughton prepared its own estimates of our proved reserves. In • estimates and related disclosures are prepared in accordance with regulatory the process of the reserves evaluation, DeGolyer and MacNaughton did not requirements. GeoPark 83 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. Report based upon its evaluation. D&M’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC There are various generally accepted methodologies for estimating reserves guidelines, future expenditures and other economic assumptions (including including volumetrics, decline analysis, material balance, simulation models interests, royalties and taxes) as provided by us. The assumptions, data, and analogies. Estimates may be prepared using either deterministic (single methods and procedures used, including the percentage of our total reserves estimate) or probabilistic (range of possible outcomes and probability of reviewed in connection with the preparation of the D&M Reserves Report occurrence) methods. The particular method chosen should be based on were appropriate for the purpose served by such report, and DeGolyer and the evaluator’s professional judgment as being the most appropriate, given MacNaughton used all methods and procedures as it considered necessary the geological nature of the property, the extent of its operating history and under the circumstances to prepare such reports. the quality of available information. It may be appropriate to employ several However, uncertainties are inherent in estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ Estimates must be prepared using all available information (open and cased control. Reserves engineering is a subjective process of estimating subsurface hole logs, core analyses, geologic maps, seismic interpretation, production/ accumulations of oil and natural gas that cannot be measured in an exact injection data and pressure test analysis). Supporting data, such as working manner, and the accuracy of any reserves estimate is a function of the quality interest, royalties and operating costs, must be maintained and updated when methods in reaching an estimate for the property. of available data and its interpretation. As a result, estimates by different such information changes materially. engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the Proved undeveloped reserves date of an estimate, economic factors such as changes in product prices As of December 31, 2017, we had 58.9 mmboe in proved undeveloped or development and production expenses, and regulatory factors, such as reserves, an increase of 10.8 mmboe, or 22%, over our December 31, 2016 royalties, development and environmental permitting and concession terms, proved undeveloped reserves of 48.1 mmboe. Changes for the year ended may require revision of such estimates. Our operations may also be affected December 31 2017, include (i) an increase of 28.4 mmboe in Colombia due by unanticipated changes in regulations concerning the oil and gas industry to the Chiricoca, Jacamar and Curucucú Field discoveries in the Llanos 34 in the countries in which we operate, which may impact our ability to recover Block and the Tigana and Jacana field extensions in the Llanos 34 Block; (ii) an the estimated reserves. Accordingly, oil and natural gas quantities ultimately increase of 1.2 mmboe due to the impact of higher average oil prices partially recovered will vary from reserves estimates. offset by a removal of 0.6 mmboe of proved undeveloped reserves related to Technology used in reserves estimation changes in the development plan in Colombia and (iii) a decrease in reserves of 5.9 mmboe from the Fell Block mainly related to a change in a previously According to SEC guidelines, proved reserves are those quantities of oil and adopted development plan and unsuccessful proved undeveloped executions. gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible—from a given date During the year ended December 31, 2017, we had 12.5 mmboe of our forward, from known reservoirs, and under existing economic conditions, proved undeveloped reserves from December 31, 2016 converted to proved operating methods and government regulations—prior to the time at which developed reserves due to development drilling in the Jacana and Tigana contracts providing the right to operate expire, unless evidence indicates oil fields in the Llanos 34 Block. See Note 37 to our Consolidated Financial Statements. 84 GeoPark 20-F Of our 58.9 mmboe of net proved undeveloped reserves, 44.4 mmboe (75%), 5.3 mmboe (9%), and 9.2 mmboe (16%) were located in Colombia, Chile and Peru, respectively. During 2017, we incurred approximately US$19.1 million in capital expenditures to convert such proved undeveloped reserves to proved developed reserves, of which approximately US$15.9 million, and US$3.2 million were made in Colombia and Chile, respectively. No net proved undeveloped reserves were located in Argentina and Brazil as of December 31, 2017. The following table shows the evolution of total net proved undeveloped (“PUD”) reserves in the year ended December 31, 2017. Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2016 48.1 (All amounts shown in mmboe) Plus: Extensions, discoveries and acquisitions: -Colombia -Chile -Brazil -Peru Less: PUD Reserves converted to proved developed reserves: -Colombia -Chile -Brazil Plus/less: PUD Reserves revisions and movement to/from other categories: -Colombia -Chile -Brazil -Peru Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2017 28.4 0.3 - - (12.5) - - 0.6 (5.9) - (0.1) 58.9 Production, revenues and price history The following table sets forth certain information on our production of oil and natural gas in Colombia, Chile, Brazil and Argentina for each of the years ended December 31, 2017, 2016 and 2015. GeoPark 85 Average daily production(1) As of December 31 2017 Colombia Chile Brazil Argentina Colombia Chile 2016 Brazil Colombia Chile 2015 Brazil 21,718 1,000 42 4 15,536 1,380 39 13,183 1,938 48 36.1 45.7 60.1 52.3 24.4 37.0 48.0 30.4 42.2 53.1 414 11,317 17,209 11,380 19,672 4.5 20.3 1.4 5.8 7.8 3.2 - - 242.6 10.0 - - 5.4 1.4 6.7 14,964 17,346 3.8 15.8 1.1 16.9 5.0 5.8 2.8 8.5 - - 8.8 1.8 4.5 21.0 1.5 4.7 4.4 2.6 7.1 21.7 11.0 252.6 10.6 22.5 Oil production Average crude oil production (bopd) Average sales price of crude oil (US$/bbl) (3) Natural gas 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) 5.9 5.6 3.2 8.8 (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 oil does not include our Argentine blocks because our Argentine operations were not material during such periods. Averaged realized sales price for gas does not include our Argentine and Colombian blocks because our gas operations in those countries were not material during such period. 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, 2017, 2016 and 2015. Tigana oil field(1) Jacana oil field(1) Rest of Colombia Chile Brazil Argentina(2) Total Oil Mbbl 2,767.0 2,566.0 1,870.0 347.0 15.0 - 2017 Gas Mmcf - - - 3,745.0 5,763.0 - 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 Oil Mbbl          1,809.7              151.3          2,615.0 2015 Gas Mmcf          - - -              707.1          4,025.4                              17.6          7,213.0                     -                       -            5,300.7        11,238.4 (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. (2) Production from CN-V Block is related to Río Grande Oeste x1 well. Declaration of commerciality is still pending as of December 31, 2017. 86 GeoPark 20-F Drilling activities The following table sets forth the exploratory wells we drilled as operators during the years ended December 31, 2017, 2016 and 2015. Exploratory wells(1) As of December 31 2017 Colombia Chile Brazil Argentina Colombia Chile 2016 Brazil Colombia Chile 2015 Brazil 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 - - - - - - - - - - - - 3.0 1.4 1.0 0.5 4.0 1.9 - - - - - - - - - - - - Productive(2) Gross Net Dry(3) Gross Net Total Gross Net (1) Includes appraisal wells. (2) A productive well is an exploratory, development, or extension well that is not a dry well. (3) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. The following table sets forth the development wells we drilled as operators during the years ended December 31, 2017, 2016 and 2015. Development wells(1) As of December 31 2017 Colombia Chile Brazil Argentina Colombia Chile 2016 Brazil Colombia Chile 2015 Brazil 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 - - - - - - 2.0 0.9 - - 2.0 0.9 - - - - - - - - - - - - Productive(2) Gross Net Dry(3) Gross Net Total Gross Net (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. (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. GeoPark 87 Developed and undeveloped acreage Present activities The following table sets forth certain information regarding our total gross Our average oil and gas production in the first quarter of 2018 was 32,195 and net developed and undeveloped acreage in Colombia, Chile, Brazil and mboepd, with oil production of 27,345 mbopd and gas production of 4,850 Peru as of December 31, 2017. mboepd. Of this total production, 82%, 9% and 9% were in Colombia, Chile and Brazil, respectively. Colombia Chile Total developed acreage Acreage(1) (in thousands of acres) Argentina Brazil Perú During the first quarter of 2018, we drilled and put into production three wells in Colombia in the Llanos 34 Block, as follows: Gross Net 8.5 4.4 8.2 7.7 1.1 0.8 Total undeveloped acreage Gross Net 239.8 119.9 799.8 590.0 1,879.9 1,410.0 Total developed and undeveloped acreage Gross Net 248.3 124.3 808.0 597.7 1,881.0 1,410.8 4.1 0.4 268.9 249.8 273.0 250.2 - - • Tigana Norte 6 development well was drilled to a total depth of 11,596 feet. A production test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of 1,360 bopd of 1,855.6 14.3 degrees API, with 0.6% water cut. 371.4 • Tigana Norte 7 development well was drilled to a total depth of 12,050 feet. A production test conducted with an electric submersible pump in 1,855.6 the Guadalupe formation resulted in a production rate of 424 bopd of 13.5 371.4 degrees API, with 15% water cut. • Jacana 20 development well was drilled to a total depth of 11,521 feet. (1)Developed acreage is defined as acreage assignable to productive wells. Undeveloped acreage is defined as acreage on which wells have not A production test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of 590 bopd of 16.8 been drilled or completed to a point that would permit the production degrees API, with 17% water cut. of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves. Net acreage based on our working interest. Additional production history is required to determine stabilized flow rates of the above mentioned wells. Productive wells The following table sets forth our total gross and net productive wells as of Also, during the first quarter of 2018, we commenced drilling Jet 1 in the February 28, 2018. Productive wells consist of producing wells and wells capable POT-T-747 block and 619-AB-1 in the POT-T-619 block exploration wells, which of producing, including natural gas wells awaiting pipeline connections to have been abandoned as of the date of this annual report. Jet 1 resulted in a commence deliveries and oil wells awaiting connection to production facilities. non-commercial oil discovery, while 619-AB-1 was abandoned after logging Gross wells are the total number of producing wells in which we have an as there was no hydrocarbon production potential. Drilling, completion and interest, and net wells are the sum of our fractional working interests owned in abandonment costs of these two wells amounted to approximately US$1.7 gross wells. million. Productive wells(1) Marketing and delivery commitments Colombia Colombia(2) Chile Brazil Peru Argentina Our production in Colombia consists primarily of crude oil. Sales for the year Oil wells Gross Net Gas wells Gross Net 90 54.8 2 0.3 47 44 49 48 - - 6 0.6 - - - - 1 0.5 - - (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 ended December 31, 2017 were made under a long term sales agreements as described below. Evacuation of the oil produced is structured under two types of sales: wellhead and pipeline. For wellhead sales, delivery point is at the loading station at fields. For pipeline sales, delivery point is at the uploading station that discharges to the national pipeline network. In Colombia, pipelines have minimum quality conditions that restrict access to the system. Consequently, and because we are mid to heavy oil producers, our entrance to the pipeline an exploratory, development, or extension well that is not a dry well. requires the use of diluents which are blended into our crude. For the year ended December 31, 2017, we sold 99% of our operated production directly at (2)We acquired Winchester and Luna in February 2012 and Cuerva in March 2012. Figures include wells drilled by Winchester, Luna and Cuerva prior to their the wellhead. acquisition by us. 88 GeoPark 20-F Oil sales are structured under a price formula based on a market reference Index (Brent or Vasconia) and discounts that consider market fees, quality, handling fees and transportation among other associated costs. We signed the Methanex Gas Supply Agreement in Chile in 2009, which Under the Trafigura Agreement, we followed agreed priorities for the volumes expired in April 30, 2017. In March 2017, we executed a new gas supply to be transported through the ODL Pipeline. For the period from March 1, agreement with Methanex effective from May 1, 2017 to December 31, 2026. 2016 to September 1, 2016, Trafigura received 10,000 bopd of our production. Under the agreement, Methanex commits to purchase up to 400,000 SCM/d In 2016 and 2017, the Trafigura Agreement was amended setting the current of gas produced by us. In 2018, due to the decline in gas production, the volumes to be delivered to Trafigura to 12,000 bopd until December 2018. commitment was reduced to 315,000 SCM/d. We also hold an option to deliver Nonperformance of our obligations of delivery in terms, amounts and quality up to 15% above this volume. of the crude to Trafigura may require us to pay Trafigura’s fare commitments in ODL Pipeline for the transport, dilution and download of crude, and may lead We gather the gas we produce in several wells through our own flow lines to early termination of the crude sales agreement as well as the immediate and inject it into several gas pipelines owned by ENAP. The transportation of repayment of any amounts outstanding under the prepayment agreement, as the gas we sell to Methanex through these pipelines is pursuant to a private well as compensation for other damages. contract between Methanex and ENAP. We do not own any principal natural gas pipelines for the transportation of natural gas. The evacuation strategy is aimed at developing synergies with both the client and the national systems, in order to obtain a reduction in costs and better If we were to lose any one of our key customers in Chile, the loss could revenues by making use of the best practices. In order to achieve this purpose, temporarily delay production and sale of our oil and gas in Chile. For a strategic alliances have been established with different agents in the transport discussion of the risks associated with the loss of key customers, See “Item chain in order to guarantee direct access to the national network. Such is 3. Key Information—D. Risk factors—Risks relating to our business—We sell the case of the implementation of an unloading facility in partnership with almost all of our natural gas in Chile to a single customer, who has in the past Oleoducto de Los Llanos. This unloading facility is located 42 km away from temporarily idled its principal facility” and “—We derive a significant portion of the Llanos 34 block. Therefore, a reduction in transportation costs has been our revenues from sales to a few key customers.” gained since the distance for trucking has been reduced significantly. If we were to lose our key customers, the loss could temporarily delay Brazil production and sale of our oil in the corresponding block. However, given Our production in Brazil consists of natural gas and condensate oil. Natural gas the wide availability of customers for Colombian crude, we believe we could production is sold through a long-term, extendable agreement with Petrobras, identify a substitute customer to purchase the impacted production volumes. which provides for the delivery and transportation of the gas produced in the Chile Manati Field to the EVF gas treatment plant in the State of Bahia. The contract is in effect until delivery of the maximum committed volume or June 2030, Our customer base in Chile is limited in number and primarily consists of ENAP whichever occurs first. The contract allows for sales above the maximum and Methanex. For the year ended December 31, 2017 we sold 100% of our oil committed volume if mutually agreed by both seller and buyer. The price production in Chile to ENAP and 95% of our gas production to Methanex, with for the gas is fixed in reais and is adjusted annually in accordance with the sales to ENAP and Methanex accounting for 10% and 9%, respectively, of our Brazilian inflation index. In July 2015, we signed an amendment to the existing total revenues in the same period. Gas Sales Agreement with Petrobras that covers 100% of the remaining gas reserves in the Manati Field. On April 21, 2017, we renewed our sales agreement with ENAP. As part of this agreement, ENAP has committed to purchase our oil production in the Fell The Manati Field is developed via a PMNT-1 production platform, which is Block in the amounts that we produce, subject to the limitation of available connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant storage capacity at the Gregorio Terminal. The sales agreement provides us through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd with the option to interrupt sales to ENAP periodically if conditions in the (9.5 mm3 per day). The existing pipeline connects the field’s platform to the export markets allow for more competitive price levels. While the agreement EVF gas treatment plant, which is owned by the field’s current concession renews automatically on an annual basis, we typically revise the agreement holders. During 2015, in order to improve the field gas recovery and every year to reflect changes in the global oil market and make certain production, Manatì’s consortium built an onshore compression plant that adjustments based on ENAP’s expenses related to storage at the Gregorio started operating in August 2015, which allowed us to classify all existing Terminal. proved undeveloped reserves as proved developed as of December 31, 2016. The BCAM-40 Concession, which includes the Manati Field, also benefits from Commercial conditions of the new agreement are similar to the previous the advantages of Petrobras’ size. As the largest onshore and offshore operator one in effect. We deliver the oil we produce in the Fell Block to ENAP at the in Brazil, Petrobras has the ability to mobilize the resources necessary to Gregorio Terminal, where ENAP assumes responsibility for the oil transferred. support its activities in the concession. ENAP owns two refineries in Chile in the north central part of the country and must ship any oil from the Gregorio Terminal to these refineries unless it is The condensate produced in the Manati Field is subject to a condensate consumed locally. GeoPark 89 purchase agreement with Petrobras, pursuant to which Petrobras has exploitation period for an area may be extended until such time as such area committed to purchase all of our condensate production in the Manati Field, is no longer commercially viable and certain other conditions are met. but only in the amounts that we produce, without any minimum or maximum Pursuant to our E&P Contracts, we are required, as are all oil and gas deliverable commitment from us. The agreement is valid through December companies undertaking exploratory and production activities in Colombia, 31, 2018, and can be renewed upon an amendment signed by Petrobras and to pay a royalty to the Colombian government based on our production the seller. Peru of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated on a In Peru, oil production is generally traded on a free market basis and field-by-field basis. See Note 32(a) to our Consolidated Financial Statements. commercial conditions generally follow international markers, normally WTI Additionally, in the event that an exploitation area has produced amounts in and Brent. As per the Joint Operating Agreement executed with Petroperu, excess of an aggregate amount established in the E&P Contract governing Petroperu has the first option to acquire oil produced by us in the Morona such area, the ANH is entitled to receive a “windfall profit,” to be paid Block by matching any offer received by third parties regarding such periodically, calculated pursuant to such E&P Contract. production. Future production in the Morona Block is expected to be transported through to pay the ANH a subsoil use fee. During the exploration period, this fee is the existing North Peruvian Pipeline. This transportation system is owned scaled depending on the contracted acreage. During the exploitation period, and operated by Petroperu, and regulated and supervised by OSINERGMIN, the fee is assessed on the amount of hydrocarbons produced, multiplied by the regulatory body in the hydrocarbons sector. Transportation rates are a specified dollar amount per barrel of oil produced or thousand cubic feet negotiated with Petroperu. However, if an agreement cannot be reached of gas produced. Further, the ANH has the right to receive an additional fee between Petroperu and us, transportation rates will be determined by when prices for oil or gas, as the case may be, exceed the prices set forth in In each of the exploration and exploitation periods, we are also obligated OSINERGMIN. The North Peruvian pipeline was out of service in 2017 due to the relevant E&P Contract. technical issues. The Peruvian government has enacted a law declaring that the pipeline’s operation is a matter of national interest, and is implementing a Our E&P Contracts are generally subject to early termination for a breach maintenance program accordingly. See “Item 3. Risk factors—Risks relating to by the parties, a default declaration, application of any of the contract’s our business—Our inability to access needed equipment and infrastructure unilateral termination clauses or termination clauses mandated by in a timely manner may hinder our access to oil and natural gas markets and Colombian law. Anticipated termination declared by the ANH results in generate significant incremental costs or delays in our oil and natural gas the immediate enforcement of monetary guaranties against us and may production.” Argentina result in an action for damages by the ANH. Pursuant to Colombian law, if certain conditions are met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the The crude produced in our CN-V block in Mendoza is sold to YPF SA (“YPF”) Colombian government during a certain period of time. See “Item 3. Key under short term agreements that can be renewed by the parties. The Information—D. Risk factors—Risks relating to our business—Our contracts Argentine crude market standard has been to transact under short term in obtaining rights to explore and develop oil and natural gas reserves agreements over the past years, making our agreement with YPF aligned to are subject to contractual expiration dates and operating conditions, and outstanding domestic market practices. YPF additionally provides us with our CEOPs, E&P Contracts and concession agreements are subject to early receipt and treatment services for a fee. termination in certain circumstances.” Significant Agreements Colombia E&P Contracts Llanos 34 Block E&P Contract . Pursuant to an E&P Contract between Unión Temporal Llanos 34 (a consortium between Ramshorn and Winchester Oil and Gas - now GeoPark Colombia SAS) and the ANH that became effective as of We have entered into E&P Contracts granting us the right to explore and March 13, 2009 (“Llanos 34 Block E&P Contract”), Unión Temporal Llanos 34 operate, as well as working interests in six blocks in Colombia. These E&P was granted the right to explore and operate the Llanos 34 Block, and we and Contracts are generally divided into two periods: (1) the exploration period, Ramshorn were granted a 40% and a 60% working interest, respectively, in the which may be subdivided into various exploration phases and (2) the Llanos 34 Block. We were also granted the right to operate the Llanos 34 Block. exploitation period, determined on a per-area basis and beginning on the On December 16, 2009, Winchester Oil and Gas (now GeoPark Colombia) date we declare an area to be commercially viable. Commercial viability entered into a joint operating agreement with Ramshorn and P1 Energy with is determined upon the completion of a specified evaluation program respect to our operations in the block. As of the date of this annual report, the or as otherwise agreed by the parties to the relevant E&P Contract. The members of the Union Temporal Llanos 34 are GeoPark Colombia SAS with 90 GeoPark 20-F 45%, and Parex Verano Limited with 55% working interest. transportation costs; (iii) simplifying logistics and reducing risks; and (iv) improving working capital. Pricing is determined at future spot market prices, We are currently in an additional exploration period (the contract provides net of transportation costs. The agreement has given us access to funding up for two optional exploratory phases of 18 months each, in which the operator to US$100 million from Trafigura, subject to applicable volumes corresponding carries out exploratory activities in order to retain areas to explore) of the to the terms of the agreement, in the form of prepaid future oil sales. Funds Llanos 34 Block E&P Contract with an exploitation program in execution committed by Trafigura will be made available to us upon request and will be over certain areas. The contract also provides for a six-year exploration repaid by us through future oil deliveries over the period of the contract, until period consisting of two three-year phases. It also provides for a 24-year December 31, 2018, with a 6-month grace period. exploitation period for each commercial area, which begins on the date on which such area is declared commercially viable. The exploitation period may During 2016 and 2017 we executed successive amendments to the Trafigura be extended for periods of up to 10 years at a time until such time as the area offtake and prepayment agreement which increased volumes delivered, is no longer commercially viable and certain conditions are met. We have improved pricing and extended the availability period for funding. presented evaluation programs to the ANH for the Tilo Field. We presented the declaration of commerciality of Max, Túa, Tarotaro, Tigana, Jacana and Chachalaca, respectively. Chile CEOPs Currently, we have five CEOPs in effect with Chile, one for each of the Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are blocks in which we operate, which grant us the right to explore and exploit required to pay a royalty to the ANH based on hydrocarbons produced in the hydrocarbons in these blocks, determine our working interests in the Llanos 34 Block. See Note 32(a) to our Consolidated Financial Statements. blocks and appoint the operator of the blocks. These CEOPs are divided into Additionally, we are required to pay a subsoil use fee to the ANH. ANH also two phases: (1) an exploration phase, which is divided into two or more has the right to receive an additional fee when prices for oil or gas, as the case exploration periods, and which begins on the effectiveness date of the may be, exceed the prices set forth in the Llanos 34 Block E&P Contract. The relevant CEOP, and (2) an exploitation phase, which is determined on a per- ANH also has an additional economic right equivalent to 1% of production, field basis, commencing on the date we declare a field to be commercially net of royalties. viable and ending with the term of the relevant CEOP. In order to transition from the exploration phase to an exploitation phase, we must declare a In accordance with the Llanos 34 Block operation contract, when the discovery of hydrocarbons to the Ministry of Energy. This is a unilateral accumulated production of each field, including the royalties’ volume, exceeds declaration, which grants us the right to test a field for a limited period of 5 million barrels and the WTI exceeds a defined base price, the Company time for commercial viability. If the field proves commercially viable, we should deliver to ANH a share of the production net of royalties in accordance must make a further unilateral declaration to the Ministry of Energy. In the with an established formula. See Note 32(a) to our Consolidated Financial exploration phase, we are obligated to fulfill a minimum work commitment, Statements. which generally includes the drilling of wells, the performance of 2D or 3D seismic surveys, minimum capital commitments and guaranties or letters Winchester and Luna Stock Purchase Agreement of credit, as set forth in the relevant CEOP. We also have relinquishment Pursuant to the stock purchase agreement entered into on February 10, 2012 obligations at the end of each period in the exploration phase in respect (the “Winchester Stock Purchase Agreement”), we agreed to pay the Sellers a of those areas in which we have not made a declaration of discovery. total consideration of US$30.0 million, adjusted for working capital. Additionally, We can also voluntarily relinquish areas in which we have not declared under the terms of the Winchester Stock Purchase Agreement, we are obligated discoveries of hydrocarbons at any time, at no cost to us. In the exploitation to make certain payments to the Sellers based on the production and sale of phase, we generally do not face formal work commitments, other than the hydrocarbons discovered by exploration wells drilled after October 25, 2011. development plans we file with the Chilean Ministry of Energy for each field Once the maximum earn-out amount is reached, we pay the Sellers quarterly declared to be commercially viable. overriding royalties in an amount equal to 4% of our net revenues from any new discoveries of oil. For the year ended December 31, 2017, we accrued and paid Our CEOPs provide us with the right to receive a monthly remuneration US$11.4 million and US$10.0 million with regards to this agreement. from Chile, payable in petroleum and gas, based either on the amount of Trafigura offtake and prepayment agreement petroleum and gas production per field or according to Recovery Factor, which considers the ratio of hydrocarbon sales to total cost of production In December 2015, we entered into an offtake and prepayment agreement (capital expenditures plus operating expenses). Pursuant to Chilean law, with Trafigura. The agreement provides that we sell and deliver a portion the rights contained in a CEOP cannot be modified without consent of the of our Colombian crude oil production to Trafigura. This benefits us by (i) parties. improving crude oil sales prices; (ii) improving operating netbacks by reducing GeoPark 91 Our CEOPs are subject to early termination in certain circumstances, which ENAP, signed 3 new CEOPs for the Isla Norte, Campanario and Flamenco vary depending upon the phase of the CEOP. During the exploration Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region. phase, Chile may terminate a CEOP in circumstances including a failure Our working interest is 60% in Isla Norte and 50% in Campanario and by us to comply with minimum work commitments at the termination Flamenco Blocks. The CEOPs have a term of 32 years, with an initial of any exploration period, or a failure to communicate our intention to exploration phase which last for 7 years, including a first exploration period proceed with the next exploration period 30 days prior to its termination, of 3 years in which we are committed to developing several exploration a failure to provide the Chilean Ministry of Energy the performance bonds activities including 1,500 square kilometers of 3D seismic registration, and required under the CEOP, a voluntary relinquishment by us of all areas the drilling of 21 exploratory wells. under the CEOP or a failure by us to meet the requirements to enter into the exploitation phase upon the termination of the exploration phase. In The hydrocarbon discoveries opened up an exploitation phase that lasts the exploitation phase, Chile may terminate a CEOP if we stop performing up to 32 years. We discovered hydrocarbon fields in the 3 blocks, starting any of the substantial obligations assumed under the CEOP without 2013 in the Flamenco Block, and in 2014 in both Campanario and Isla Norte cause and do not cure such nonperformance pursuant to the terms of Blocks. The CEOPs provide us with a right to receive a remuneration payable the concession, following notice of breach from the Chilean Ministry of by means of a fraction of the production sold, which in the TDF Blocks is Energy. Additionally, Chile may terminate the CEOP due to force majeure based on a formula depending on the recovery of the total accumulated circumstances (as defined in the relevant CEOP). If Chile terminates a CEOP expenses incurred (capital expenditure plus operational expenditure plus in the exploitation phase, we must transfer to Chile, free of charge, any administrative and general expenses). While the recovery factor is less than productive wells and related facilities, provided that such transfer does not 1.0, the remuneration is 95% of the hydrocarbons produced, either oil or gas. interfere with our abandonment obligations and excluding certain pipelines If the recovery factor surpasses 1.0, a formula applies reducing gradually the 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 Brazil are subject to contractual expiration dates and operating conditions, and Rio das Contas Quota Purchase Agreement our CEOPs, E&P Contracts and concession agreements are subject to early Pursuant to the Rio das Contas Quota Purchase Agreement we entered into termination in certain circumstances.” on May 14, 2013, we agreed to acquire from Panoro all of the quotas issued by Rio das Contas for a purchase price of US$140 million (subject to working Fell Block CEOP . On November 5, 2002, we acquired a percentage of rights and capital adjustments at closing and further earn-out payments, if any) upon interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and satisfaction of certain conditions. With respect to the earn-out payments, the on May 10, 2006, we became the sole owners, with 100% of the rights and Rio das Contas Quota Purchase Agreement provides that during the calendar interest in the Fell Block CEOP. Chile had originally entered into a CEOP for the periods beginning on January 1, 2013 and ending as late as December 31, Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April 29, 1997, 2017, we will make annual earn-out payments to Panoro in an amount equal which had an effective date of August 25, 1997. The Fell Block CEOP grants us to 45% of “net cash flow,” calculated as EBITDA less the aggregate of capital the exclusive right to explore and exploit hydrocarbons in the Fell Block and expenditures and corporate income taxes, with respect to the BCAM-40 has a term of 35 years, beginning on the effective date. The Fell Block CEOP Concession of any amounts in excess of US$25.0 million, up to a maximum provided for a 14-year exploration period, composed of numerous phases that cumulative earn-out amount of US$20.0 million in a five-year period. Once the ended in 2011, and an up-to-35-year exploitation phase for each field. maximum earn-out amount is reached or the five-year period has elapsed, no further earn-out amounts will be payable. For the year ended December 31, The Fell Block CEOP provides us with a right to receive a monthly retribution 2017, there were no earn-out payments with regards to this agreement. 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 We financed our Rio das Contas acquisition in part through our Brazilian 5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas production of up to 882.9 mmcfpd. In the event that we exceed these levels Credit Facility”) with Itaú BBA International plc, which is secured by the of production, our monthly retribution from Chile will decrease based on a benefits we receive under the Purchase and Sale Agreement for Natural Gas sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the with Petrobras. See “Item 5. Operating and Financial Review and Prospects—B. oil and 60% of the gas that we produce per field. Liquidity and capital resources—Indebtedness—Rio das Contas Credit Facility.” The loan was fully repaid in September 2017. TDF Blocks CEOPs . After an international bidding process led by ENAP and the Chilean Ministry of Energy, in March and April, 2012, we, together with 92 GeoPark 20-F Overview of concession agreements minimum exploration program proposed in the winning bid; (4) activities for The Brazilian oil and gas industry is governed mainly by the Brazilian the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments Petroleum Law, which provides for the granting of concessions to operate for government participation; and (7) responsibility for the costs associated petroleum and gas fields in Brazil, subject to oversight by the ANP. A with the deactivation and abandonment of the facilities in accordance with concession agreement is divided into two phases: (1) exploration and (2) Brazilian law and best practices in the oil industry. development and production. The exploration phase, which is further divided into two subsequent exploratory periods, the first of which begins on the date A concessionaire is required to pay to the Brazilian government the following: of execution of the concession agreement, can last from three to eight years • a license fee; (subject to earlier termination upon the total return of the concession area • rent for the occupation or retention of areas; 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 concession is subject to the discretion of the ANP. must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable The main terms and conditions of a concession agreement are set forth regulations, and is payable on a quarterly basis for each field from the date in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of on which extraordinary production occurs. This participation fee, whenever the concession area; (2) validity and terms for exploration and production due, varies between 0% and 40% of net revenues depending on (1) the activities; (3) conditions for the return of concession areas; (4) guarantees to volume of production and (2) whether the concession is onshore or in shallow be provided by the concessionaire to ensure compliance with the concession water or deep water. Under the Brazilian Petroleum Law and applicable agreement, including required investments during each phase; (5) penalties regulations issued by the ANP, the special participation fee is calculated in the event of noncompliance with the terms of the concession agreement; based on the quarterly net revenues of each field, which consist of gross (6) procedures related to the assignment of the agreement; and (7) rules for revenues calculated using reference prices established by the ANP (reflecting the return and vacancy of areas, including removal of equipment and facilities international prices and the exchange rate for 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 GeoPark 93 royalty payment equal to 7.5% of the production of oil and natural gas in the right to terminate it. The BCAM-40 Concession consortium has also entered concession area. In addition, in case the special participation fee of 10% shall into a joint operating agreement, which sets out the rights and obligations of be applicable for a field in any quarter of the calendar year, the concessionaire the parties in respect of the operations in the concession. is obliged to make qualified research and development investments equivalent to one percent of the field’s gross revenue. Area retention payments are also Petrobras Natural Gas Purchase Agreement applicable under the concession agreement. We acquired Rio das Contas’ 10% QGEP, GeoPark Brasil, Brasoil and Petrobras are party to a natural gas purchase participation interest in the BCAM-40 Concession on March 31, 2014. agreement providing for the sale of natural gas by QGEP, GeoPark Brasil and Rounds 11, 12, 13 and 14 Concession Agreements. term of agreement. The Petrobras Natural Gas Purchase Agreement is valid Under the Rounds 11, 12, 13 and 14 Concession Agreements, the ANP is until the earlier of Petrobras’ receipt of this total contractual quantity or June entitled to a monthly royalty corresponding to up to 10% of the production 30, 2030. The agreement may not be fully or partially assigned except upon of oil and natural gas in the concession area, in addition to the special execution of an assignment agreement with the written consent of the other participation fee described above, the payment for the occupation of the parties, which consent may not be unreasonably withheld provided that Brasoil to Petrobras, in an amount of 812 billion cubic feet (“bcf”) over the concession area of approximately R$7,600 per year and the payment to the certain prerequisites have been met. owners of the land of the concession equivalent to one percent of the oil and natural gas produced in the concession area. The agreement provides for the provision of “daily contractual quantities” to Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until During bidding, a work program offer is made in the form of work units and 2030. The parties may agree to lower volumes as dictated by Manati Field’s the ANP asks for a guarantee of a monetary amount proportional to the depletion. Pursuant to the agreement, the base price is denominated in reais offered units. However, depending on the work performed by the operator, and is adjusted annually for inflation pursuant to the general index of market the actual work program investment might have a different value to the prices (IGPM). Additionally, the gas price applicable on a given day is subject guaranteed value. Overview of consortium agreements to reduction as a result of the gas quantity acquired by Petrobras above the volume of the annual TOP commitment (85% of the daily contracted quantity) in effect on such day. The Petrobras Natural Gas Purchase Agreement provides A consortium agreement is a standard document describing consortium that all of the Manati Field’s daily production be sold to Petrobras. members’ respective percentages of participation and appointment of the operator. It generally provides for joint execution of oil and natural Peru gas exploration, development and production activities in each of the Morona Block concession areas. These agreements set forth the allocation of expenses for On October 1, 2014, we entered into an agreement with Petroperu to acquire each of the parties with respect to their respective participation interests an interest in and operate the Morona Block, located in Northern Peru. We will in the concession. The agreements are supplemented by joint operating assume a 75% working interest of the Morona Block, with Petroperu retaining agreements, which are private instruments that typically regulate the a 25% working interest. On December 1, 2016, through Supreme Decree N° aggregation of funds, the sharing of costs, mitigation of operational risks, 031-2016-MEN the Peruvian government approved the amendment to the preemptive rights and the operator’s activities. License Contract of Block 64 (Morona Block) appointing GeoPark as operator and holder of 75% of the Contract. An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph In Peru, there is a 5-20% sliding scale royalty rate, depending on production 1, of the Brazilian Corporate Law) is the joint liability among consortium levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For members as established in the Brazilian Petroleum Law (Article 38, item II). production between 5,000 and 100,000 bopd there is a linear sliding scale between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%. BCAM-40 Consortium Agreement On January 14, 2000, Petrobras, QG Perfurações and Petroserv entered See “Item 4. Information on the Company—B. Business Overview—Our into a consortium agreement, or the BCAM-40 Consortium Agreement, for operations—Operations in Peru—Morona Block.” the performance of the BCAM-40 Concession Agreement. Petrobras is the operator of the BCAM-40 concession, with a 35% participation interest. QGEP, Argentina Brasoil and Rio das Contas have a 45%, 10% and 10% participation interest, Overview of exploration permits respectively. The BCAM-40 Consortium Agreement has a specified term of Our exploration permits grant to us and our partners the exclusive right to 40 years, terminating on January 14, 2040 and, at the time the obligations explore for hydrocarbons and declare a commercial discovery within the acreage undertaken in the agreement are fully completed, the parties will have the of our permits. Our exploration permits are made up of three subperiods, each lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years. 94 GeoPark 20-F We are bound to pursue specific minimum work or investment commitments gas production of 2,700 boepd (70% light oil and 30% gas), 137,000 acres during each of the subperiods of each exploration permit. Such exploration well-positioned in the Neuquen Basin and production facilities, including works are valued in work units assigned to each particular type of work under hydrocarbons treatment, storage, and delivery infrastructure. the applicable bidding conditions. Work and investment programs for the permits are required to be assured by We paid the consideration using proceeds from the offering of the Notes due issuing a performance bond for the value of the committed work plan. 2024. The acquisition of the blocks closed on March 27, 2018. Under the terms of our exploration permits and concession agreements, we are Agreements with LGI entitled to our proportionate share of the hydrocarbons production lifted from LGI Colombia Agreements each block. The Province of Mendoza’s state owned company, EMESA, has a 10% In December 2012, we agreed with LGI to extend our strategic partnership carried interest in each of the Puelen and Sierra del Nevado permits and any to build a portfolio of upstream oil and gas assets throughout Latin America. future exploitation concessions, while there is no governmental participation On December 18, 2012, LGI agreed to acquire a 20% equity interest in in the CN-V Block. During the term of our exploration permits, we are also GeoPark Colombia SAS by making a US$14.9 million capital contribution required, under Argentine law, to pay a 15% royalty to the province on both oil and a US$4.9 million loan to GeoPark Colombia SAS and miscellaneous and gas sales. In case we progress to an exploitation concession, the applicable reimbursements. Concurrently, we entered into a shareholders’ agreement royalty rate will reduce to a 12% royalty. We also pay annual surface rental with LGI (the “LGI Colombia Shareholders’ Agreement”) setting forth fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and LGI’s and our respective obligations in connection with LGI’s investment Resolution 588/98 of the Argentine Secretariat of Energy and Decree 1454/2007, in our Colombian oil and gas business through GeoPark Colombia SAS. and certain landowner fees. Furthermore, LGI and Winchester (now GeoPark Colombia SAS) entered into a loan agreement, whereby, upon the closing of LGI’s subscription of Our Argentine exploration permits have no change of control provisions, though shares in GeoPark Colombia SAS, LGI granted a credit line (of which US$4.9 any assignment of these concessions is subject to the prior authorization by the million was drawn at closing) to Winchester of up to US$12.0 million, to executive branch of the Province of Mendoza and rights of first refusal in favor be used for the acquisition, development and operation of oil and gas of our partners and EMESA, in the case of the Puelen and Sierra del Nevado assets in Colombia. Further, on January 8, 2014, following an internal permits. Each of these permits or future concessions can be terminated for corporate reorganization of our Colombian operations, GeoPark Colombia default in payment obligations and/or breach of material statutory or regulatory Coöperatie U.A. and GeoPark Latin America entered into a new members’ obligations. We are subject to the obligation to relinquish at least 50% of the agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out acreage of each exploration permit at the end of each exploration subperiod. We substantially similar rights and obligations to the LGI Colombia Shareholders’ may also voluntarily relinquish acreage to the provincial authorities. Agreement in respect of our oil and gas business through GeoPark Colombia SAS only. We refer to the LGI Colombia Shareholders’ Agreement and the LGI Our Argentine exploration permits are governed by the laws of Argentina and Colombia Members’ Agreement collectively as the LGI Colombia Agreements. the resolution of any disputes must be sought in the Mendoza Provincial Courts. If and when we make a commercial discovery in one or more of our exploration Under the LGI Colombia Agreements, LGI agreed to assume its share of the permits, we will have the right to request and obtain an exploitation concession existing debt of GeoPark Colombia SAS and to provide additional funding to produce hydrocarbons in the block for 25 years, with an optional extension to cover LGI’s share of required future investments in Colombia through of up to 10 years. We also receive the right to be granted a 35-year oil transport GeoPark Colombia SAS. In addition, we can earn back up to 12% additional concession to build and make use of pipelines or other transport facilities equity interests in GeoPark Colombia depending on the success of our beyond the boundaries of the concession. Colombian operations. Additionally, oil and gas producers in Argentina must grant a privilege to the Currently, GeoPark Colombia Coöperatie has four directors, out of which one domestic market to the detriment of the export market, including hydrocarbon Director is elected by LGI. The LGI Colombia Agreements require the consent export restrictions, domestic price controls, export duties and domestic market of LGI or the LGI-appointed director for GeoPark Colombia SAS to take certain supplier obligations. actions, including, among others: Pluspetrol Asset Purchase Agreement • making any decision to terminate or permanently or indefinitely suspend operations in or surrender our blocks in Colombia (other than as required Pursuant to the APA that we entered into on December 18, 2017 with under the terms of the relevant concessions for such blocks); Pluspetrol, we agreed to acquire a 100% working interest and operatorship • creating of a security interest over our blocks in Colombia; of the Aguada Baguales, El Porvenir and Puesto Touquet blocks in Argentina • approving of GeoPark Colombia’s annual budget and work programs and for a total consideration of $52 million. The blocks include estimated oil and the mechanisms for funding any such budget or program; • entering into of any borrowings other than those provided in an approved GeoPark 95 budget or incurred in the ordinary course of business to finance working The respective boards of each of GeoPark Chile and GeoPark TdF supervise capital needs; their day-to-day operations. Each of these boards has four directors. As long • granting any guarantee or indemnity to secure liabilities of parties other as LGI holds at least 5% of the voting shares of GeoPark Chile, LGI has the than those of our Colombian subsidiaries; right to elect one director and such director’s alternate, and the remaining • changing the dividend, voting or other rights that would give preference to directors, and alternates, are elected by us. As long as LGI holds at least 5% or discriminate against the shareholders of GeoPark Colombia; of the voting shares of GeoPark TdF, LGI has the right to elect one director • entering into certain related party transactions; and such director’s alternate, and the remaining directors, and alternates, are • paying dividends from GeoPark Colombia Coöperatie; and elected by GeoPark Chile. • disposing of any material assets other than those provided for in an approved budget and work program. The LGI Chile Shareholders’ Agreements require the consent of LGI or the LGI appointed director in order for GeoPark Chile and GeoPark TdF, as the case We have also agreed to ensure that the board of directors and rules and may be, to take certain actions, including, among others: management of our other subsidiaries engaged in our Colombian oil and gas • making any decision to terminate or permanently or indefinitely suspend business are subject to the same principlesa nd restrictions outlined above. operations in or surrender our blocks in Chile (other than as required under the terms of the relevant CEOP for such blocks or required by law); The LGI Colombia Agreements provide that if either we or LGI decide to sell • selling our blocks in Chile to our affiliates; our respective participation in GeoPark Colombia Coöperatie, the transferring • any change to the dividend, voting or other rights that would give party must make an offer to sell its participation to the other party before preference to or discriminate against the shareholders of GeoPark Chile and selling those shares to a third party. In addition, any sale to a third party is GeoPark TdF; subject to tag-along and drag-along rights, and the non-transferring party has • entering into certain related party transactions; and the right to object to a sale to the third-party if it considers such third-party to • creating a security interest over our blocks in Chile (other than in be not of a good reputation or one of our direct competitors. connection with a financing that benefits our Chilean subsidiaries). Under the LGI Colombia Agreements, we have agreed, along with LGI, to The LGI Chile Shareholders’ Agreements provide that if LGI or either Agencia vote or otherwise cause GeoPark Colombia SAS to declare dividends only or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark TdF, as after allowing for retentions for approved work programs and budgets and the case may be, the transferring shareholder must make an offer to sell those capital adequacy requirements of GeoPark Colombia Coöperatie, working shares to the other shareholder before selling those shares to a third party. In capital requirements, banking covenants associated with any loan entered addition, any sale to a third party is subject to tag-along and drag-along rights, into by GeoPark Colombia Coöperatie and its subsidiary. See “Item 3. Key and the non-transferring shareholder has the right to object to a sale to the Information—D. Risk factors—Risks relating to our business—LGI, our third-party if it considers such third-party to be not of a good reputation or strategic partner in Chile and Colombia, may not consent to our taking one of our direct competitors. Under the LGI Chile Shareholders’ Agreements, certain actions or may eventually decide to sell its interest in our Chilean and we and LGI have also agreed to vote our common shares or otherwise cause Colombian operations to a third party.” LGI Chile Shareholders’ Agreements GeoPark Chile or GeoPark TdF, as the case may be, to declare dividends only after allowing for retentions to meet anticipated future investments, costs and obligations. See “Item 3. Key Information—D. Risk factors—Risks relating In 2010, we formed a strategic partnership with LGI to jointly acquire and to our business—LGI, our strategic partner in Chile and Colombia, may not develop upstream oil and gas projects in Latin America. In 2011, LGI acquired consent to our taking certain actions or may eventually decide to sell its a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark interest in our Chilean and Colombian operations to a third party.” TdF, for a total consideration of US$148.0 million, plus additional equity funding of US$18.0 million over the following three years. On May 20, 2011, Title to properties in connection with LGI’s investment in GeoPark Chile, we entered into a In each of the countries in which we operate, the state is the exclusive owner shareholders’ agreement with LGI (as amended on July 4, 2011 and October of all hydrocarbon resources located in such country and has full authority 4, 2011, the “GeoPark Chile Shareholders’ Agreement”) and a subscription to determine the rights, royalties or compensation to be paid by private agreement (as amended on July 4, 2011 and October 4, 2011), On October investors for the exploration or production of any hydrocarbon reserves. In 2011, in connection with LGI’s investment in GeoPark TdF, we entered Chile, the Republic of Chile grants such rights through a CEOP. In Colombia, into a shareholder´s agreement with LGI (the “GeoPark TdF Shareholders the Republic of Colombia grants such rights through E&P Contracts or Agreement”, and together with the GeoPark Chile Shareholders’ Agreement, contracts of association. In Argentina, the Argentine Republic grants such the “LGI Chile Shareholders’ Agreements”), setting forth LGI’s and our rights through exploitation concessions. In Brazil, the Federative Republic respective rights and obligations in connection with LGI’s investment in our of Brazil grants such rights pursuant to concession agreements. See “Item 3. Chilean oil and gas business. 96 GeoPark 20-F Key Information—D. Risk factors—Risks relating to the countries in which competition from other independent operators and from major state-owned we operate—Oil and natural gas companies in Colombia, Chile, Brazil, Peru oil companies in acquiring and developing licenses in the countries where we and Argentina do not own any of the oil and natural gas reserves in such operate or plan to operate. countries.” Other than as specified in this annual report, we believe that we have satisfactory rights to exploit or benefit economically from the oil and Many of these competitors have financial and technical resources and gas reserves in the blocks in which we have an interest in accordance with personnel substantially larger than ours. As a result, our competitors may be standards generally accepted in the international oil and gas industry. Our able to pay more for desirable oil and natural gas assets, or to evaluate, bid CEOPs, E&P Contracts, contracts of association, exploitation concessions for and purchase a greater number of licenses than our financial or personnel and concession agreements are subject to customary royalty and other resources will permit. Furthermore, these companies may also be better able interests, liens under operating agreements and other burdens, restrictions to withstand the financial pressures of unsuccessful wells, sustained periods of and encumbrances customary in the oil and gas industry that we believe volatility in financial and commodities markets and generally adverse global do not materially interfere with the use of or affect the carrying value of our and industry-wide economic conditions, and may be better able to absorb the interests. See “Item 3. Key Information—D. Risk factors—Risks relating to burdens resulting from changes in relevant laws and regulations, which may our business—We are not, and may not be in the future, the sole owner or adversely affect our competitive position. See “Item 3. Key Information—D. operator of all of our licensed areas and do not, and may not in the future, Risk factors—Risks relating to our business—Competition in the oil and hold all of the working interests in certain of our licensed areas. Therefore, we natural gas industry is intense, which makes it difficult for us to attract capital, may not be able to control the timing of exploration or development efforts, acquire properties and prospects, market oil and natural gas and secure associated costs, or the rate of production of any non-operated and, to an trained personnel.” extent, any non-wholly-owned, assets.” Our customers We may also be affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the In Colombia, our primary customer is Trafigura, and who represented 79%, demand for drilling rigs, supplies, services, equipment and crews, and can of our total revenues for the year ended December 31, 2017. In Chile, our lead to shortages of, and increasing costs for, drilling equipment, services and primary customers are ENAP and Methanex. As of December 31, 2017, ENAP personnel. Shortages of, or increasing costs for, experienced drilling crews and purchased all of our oil and condensate production and Methanex purchased equipment and services could restrict our ability to drill wells and conduct our almost all of our natural gas production in Chile, and represented 5% and 5%, operations. respectively, of our total revenues for the year ended December 31, 2017. In Brazil, all of our hydrocarbons in Manati are sold to Petrobras. In Peru, our Health, safety and environmental matters primary customer may be Petroperu, has the first option to acquire the oil General produced by us in the Morona Block by matching any offer received by third Our operations are subject to various stringent and complex international, parties regarding such production. Seasonality federal, state and local environmental, health and safety laws and regulations in the countries in which we operate. These laws and regulations govern matters including the emission and discharge of pollutants into the ground, Although there is some historical seasonality to the prices that we receive air or water; the generation, storage, handling, use and transportation of 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 The oil and gas industry is competitive, and we may encounter strong • limit or prohibit seismic and drilling activities in certain locations lying within or near protected or environmentally sensitive areas; GeoPark 97 • require preventative measures to mitigate pollution from our operations, understanding and management. Within our S.P.E.E.D. philosophy we which, if not undertaken, could subject us to substantial penalties; and have a team that is exclusively focused on securing the environmental • require us to maintain a safe and healthy working environment for all authorizations and permits for the projects we undertake. This professional employees, contractors and visitors in accordance with applicable regulations and trained team, specialized in environmental issues, is also responsible and industry best practices. for the achievement of the environmental standards set by our Board of Directors and for training and supporting our personnel. Our senior These laws and regulations may also restrict the rate of oil and natural gas executives, personnel in the field, visitors and contractors have also received production below the rate that would otherwise be possible. Compliance training in proper environmental management. with these laws can be costly. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and Our Health and Safety Policy consequently affects profitability. We believe that the implementation of additional safety tools in our operations in 2016 has significantly contributed to control and minimizing Public interest in the protection of the environment continues to increase. risks in our operations. Actions taken by us included the development of a Drilling in some areas has been opposed by certain community and new Proactive Observation Program, HSE training, permits to work, internal environmental groups and, in other areas, has been restricted. audits, drills, pre-job meetings and job safety analysis, among others. As Climate change of December 31, 2017, on the last 12-month basis, our HSE development statistics workforce shows that Lost Time Injury Frequency (LTIF) was 1.14 (out Both our operations and the combustion of oil and natural gas-based of every 1,000,000 worked hours), our Total Recordable Incident Rate (TRIR) products results in the emission of greenhouse gases, which may contribute was 2.86 (out of every 1,000,000 worked hours) and we had no fatal incidents to global climate change. Climate change regulation has gained momentum related to operations in 2017. in recent years internationally and at the federal, regional, state and local levels. On the international level, various nations have committed to reducing In 2016, we subscribed to the International Association of Oil and Gas their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto Producers in order to align our Management System and policies with the Protocol was set to expire in 2012. In late 2011, an international climate best international standards. change conference in Durban, South Africa resulted in, among other things, an agreement to negotiate a new climate change regime by 2015 that Certain Bermuda law considerations would aim to cover all major greenhouse gas emitters worldwide, including As a Bermuda exempted company, we and our Bermuda subsidiaries are the U.S., and take effect by 2020. In November and December 2012, at an subject to regulation in Bermuda. We have been designated by the BMA as a international meeting held in Doha, Qatar, the Kyoto Protocol was extended non-resident for Bermuda exchange control purposes. This designation allows by amendment until 2020. In addition, the Durban agreement to develop us to engage in transactions in currencies other than the Bermuda dollar, the protocol’s successor by 2015 and implement it by 2020 was reinforced. and there are no restrictions on our ability to transfer funds (other than funds We are committed to controlling the emission of greenhouse gases and denominated in Bermuda dollars) in and out of Bermuda. implementing available technologies to reduce the impact caused by our operations. For example, during 2016 we began a migration plan to replace Under Bermuda’s law, “exempted” companies are companies formed for the diesel with natural gas and electric generation. purpose of conducting business outside Bermuda from a principal place Our HSE Management System of business in Bermuda. As exempted companies, we and our Bermuda subsidiaries may not, without a license or consent granted by the Minister of Our health, safety and environmental management plan is focused on Finance of Bermuda, participate in certain business transactions, including undertaking realistic and practical programs based on recognized world transactions involving Bermuda landholding rights and the carrying on of practices. Our emphasis is on building key principles and company-wide business of any kind for which we or our Bermuda subsidiaries are not licensed ownership and then expanding programs as we continue growing. Our in Bermuda. S.P.E.E.D. philosophy and our HSE Plan have been developed with reference to ISO 14001 for environmental management issues, OHSAS 18001 for Insurance occupational health and safety management issues, SA 8000 for social We maintain insurance coverage of types and amounts that we believe to accountability and workers’ rights issues and applicable World Bank Standards. be customary and reasonable for companies of our size and with similar Our Environmental Policy operations in the oil and gas industry. However, as is customary in the industry, we do not insure fully against all risks associated with our business, Our policy looks forward to meet or exceed environmental regulations either because such insurance is not available or because premium costs are in the countries in which we operate. We believe that oil and gas can be considered prohibitive. produced in an environmentally-responsible manner with proper care, 98 GeoPark 20-F Currently, our insurance program includes, among other things, construction, Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, fire, vehicle, technical, umbrella liability, director’s and officer’s liability and establishes the general procedures and requirements that must be completed employer’s liability coverage. Our insurance includes various limits and by a private investor and disclosure procedures that need to be followed deductibles or retentions, which must be met prior to or in conjunction with during the performance of these activities. recovery. A loss not fully covered by insurance could have a materially adverse effect on our business, financial condition and results of operations. See “Item Exploration and production activities were governed by Decree 1895 of 1973 3. Key Information—D. Risk factors—Risks relating to our business—Oil and until September 2009. Decree Law 2310 of 1974 (as complemented by Decree gas operations contain a high degree of risk and we may not be fully insured 743 of 1975) governed the contracts and contracting processes carried out by against all risks we face in our business.” Ecopetrol and the rules applicable to such contracts, and also provided that Industry and regulatory framework Colombia Regulation of the oil and gas industry Ecopetrol was responsible for administering the hydrocarbons resources in the Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, but all agreements entered into by us prior to 2003 with other oil companies are still regulated by Decree 2310 of 1974. The ANH is responsible for managing all exploration lands not subject to previously existing association contracts with Ecopetrol. The ANH began The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and offering all undeveloped and unlicensed exploration areas in the country Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced by under E&P Contracts and Technical Evaluation Agreements, or TEAs, which Accord 004 of 2012, issued by the Directive Council of the ANH, sets forth the resulted in a significant increase in Colombian exploration activity and necessary steps for entering into E&P Contracts with the ANH. This Agreement competition, according to the ANH. The ANH is also in charge of negotiating only regulates the contracts entered into as of May 4, 2012. Prior contracts are and executing contracts through “direct negotiation” mechanisms with still ruled by Agreement 008 of 2004. Due to the oil prices crisis of 2015, the attention to special conditions in the areas to be explored. The regulatory ANH implemented transitory measures through Agreements 002, 003, 004 and landscape in Colombia has recently changed. The regime for the ANH’s 005 of 2015, which are still in place. The ANH is working on a new Agreement contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. that compiles the relevant rulings in one document. Accord 008 of 2004 issued by the Directive Council of the ANH, as repealed and replaced by Accord 004 of 2012, sets forth the necessary steps for entering Resolution 18-1495 of 2009 establishes a series of regulations regarding into E&P Contracts with the ANH. This Agreement regulates E&P contracts hydrocarbon exploration and exploitation. In the E&P Contracts, operators are entered into from May 4, 2012. E&P contracts entered into before that date are afforded access to non-contracted blocks by committing to an exploration still regulated by Agreement 008 of 2004. Due to the oil price crisis of 2015, the work program. These E&P Contracts provide companies with 100% of new ANH implemented transitory measures through Agreements 002, 003, 004 and production, less the participation of the ANH, which participation may differ 005 of 2015. On May 18, 2017, the ANH issued Agreement 002, which repealed for each E&P Contract and depends on the percentage that each company and replaced Agreement 004 of 2012 and transitory measures adopted in has offered to the ANH in order to be granted with a block, subject to an initial 2014 and 2015.  Agreement 002 of 2017 established rules for the allocation of royalty payment of 8% and the payment of income taxes of 33%. In addition, hydrocarbon areas and adopted criteria for the exploration and exploitation the Colombian government also introduced TEAs, in which companies that of hydrocarbons owned by Colombia, including the selection of contractors, enter into TEAs are the only ones to have the right to explore, evaluate and and management, execution, termination, liquidation, monitoring, control select desirable exploration areas and to propose work commitments on and supervision of corresponding contracts. Agreement 002 of 2017 regulates those areas, and have a preemptive right to enter into an E&P Contract, contracts entered into from May 18, 2017. E&P contracts entered into before thereby providing companies with low-cost access to larger areas for that date are still regulated by the Agreements under which they were preliminary evaluation prior to committing to broader exploration programs. executed, except for any modification, addition, extension, assignment and A preemptive right is granted to convert the TEA into an E&P Contract. other action related to the execution of contracts submitted by the parties to Exploration activities can only be carried out by the TEA contractor. the ANH after May 18, 2017, which are regulated by Agreement 002 of 2017. Regulatory framework Pursuant to Colombian law, companies are obligated to pay a percentage of their production to the ANH as royalties and an economic right as ANH’s Regulation of exploration and production activities participating interest in the production. Producing fields pay royalties in Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon accordance with the applicable royalty program at the time of the discovery. 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 GeoPark 99 main taxes currently in effect—after the December 2016 tax reform discussed year. below—are the income tax (40% for 2017, 37% for 2018 and 33% for 2019 • IFRS is the basis for tax purposes with certain exceptions, such as: onwards), sales or value added tax (19%), and the tax on financial transaction – Depreciation: The general rule is that the term of depreciation is (0.4%). Additional regional taxes also apply. Colombia has entered into a determined according to IFRS, but with a depreciation percentage cap number of international tax treaties to avoid double taxation and prevent tax per year for tax purposes. Assets held before 2017 will be depreciated evasion in matters of income tax and net asset tax. according to the previous rules. Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international – Amortization: Amortization of investments in the oil and gas industry to be investment regime, regulates foreign capital investment in Colombia. depleted according to the “units of production method” beginning 2028. Resolution 8 of the board of the Colombian Central Bank, or the Exchange Beginning in fiscal year 2017 and until 2027 , exploratory investments will be Statute, and its amendments contain provisions governing exchange amortized by the straight line method in a period of 5 years. Grandfather rule operations. Articles 48 to 52 of Resolution 8 provide for a special exchange was established for undepleted investments held before fiscal year 2017 regime for the oil industry that removes the obligation of repayment to the • Goodwill in the acquisition of shares is no longer subject to amortization. foreign exchange market currency from foreign currency sales made by Goodwill generated before 2017 will be subject to amortization according to foreign oil companies. Such companies may not acquire foreign currency the rules enforceable at the moment of generation of the goodwill, however in the exchange market under any circumstances and must reinstate in the amortization of the undepleted values as of January 1, 2017 may not take foreign exchange market the capital required in order to meet expenses in more than five years, and must be done through the straight line method. Colombian legal currency. Companies can avoid participating in this special • VAT modifications: (a) general rate increased to 19%; (b) eight month window oil and gas exchange regime, however, by informing the Colombian Central period to credit input tax; (c) input tax, on the acquisition or importation of Bank, in which case they will be subject to the general exchange regime of fixed assets may be deductible for income tax purposes, unless it is to be Resolution 8 and may not be able to access the special exchange regime for a treated as creditable, or as part of the tax cost of the asset; and (d) sale of period of 10 years. crude oil to refineries subject to VAT at a rate of 19%. • Banking tax (4x1000), to become permanent. In December 2016, the Colombian Congress approved a tax reform (Law 1819 • Benefits for the oil and gas industry: taxpayers that increase investments in of 2016). The main aspects of the reform are summarized below. exploration of new hydrocarbon reserves, incorporation of new recoverable • The enterprise contribution on equality (“CREE” for its Spanish acronym) tax is reserves, and the addition of proven reserves, would have the right to a Tax eliminated, but a carry forward of CREE receivables and losses for income tax Refund Certificate (CERT), which could be used to pay taxes administered purposes will be permitted. by the Colombian Tax Office or sold in the market to • Income tax rates will be 34% plus a 6% surcharge for fiscal year 2017, 33% plus other taxpayers. a 4% surcharge for fiscal year 2018 and 33% for fiscal year 2019 and beyond. • Tax may be paid according to the following two options: • A dividend tax is included on distributions from Colombian corporations – Paying up to 50% of the amount of the tax of one fiscal year, by investing for non-resident shareholders, with tax rates of 5%, for dividends which in social projects. were taxed at the corporate level and 35% and then a 5% on the remaining – Using the value of the investment to pay 50% of the tax, during a period amount for dividends which were not taxed at the corporate level. of 10 years in equal installments. • Grandfather rules prevent the application of the 5% dividend tax on profits In either case, the investments may not be of the nature of those that obtained before fiscal year 2017. The tax rate for profits obtained before that constitute deductible expenses. date which were not taxed at the corporate level would be 33% instead of 35%. Chile • Tax losses to be carried forward up to 12 years, losses generated before 2017 Regulation of the oil and gas industry are grandfathered. Under the Chilean Constitution, the state is the exclusive owner of all mineral • Presumptive taxable base increases to 3.5% of the net equity at the end of and fossil substances, including hydrocarbons, regardless of who owns the the prior year. land on which the reserves are located. The exploration and exploitation • Cross border payments withholding tax suffered modifications. The general of hydrocarbons may be carried out by the state, companies owned by the rule on services is that there will be a 15% withholding tax, which includes state or private entities through administrative concessions granted by the management fees, even if the service is rendered form abroad. Additionally, President of Chile by Supreme Decree or CEOPs executed by the Minister of services rendered from abroad will be subject to VAT if the beneficiary is in Energy. Exploitation rights granted to private companies are subject to special Colombia (for example services rendered to GeoPark Colombia from abroad taxes and/or royalty payments. The hydrocarbon exploration and exploitation would be subject to such treatment). industry is supervised by the Chilean Ministry of Energy. • The net wealth tax is still set to expire in fiscal year 2017 for corporations, but it remains unclear if its term will be extended. The tax is not enforceable In Chile, a participant is granted rights to explore and exploit certain assets for 2018, but may be enforceable in 2019 if a law is passed by the end of this under a CEOP. If a participant breaches certain obligations under a CEOP, the 100 GeoPark 20-F participant may lose the right to exploit certain areas or may be required the income accrued or received during 2013 and onward. Dividends or profits to return all or a portion of the awarded areas to Chile with no right of distributed to the foreign shareholders of the contractors are subject to 35% compensation. Although the government of Chile cannot unilaterally modify Additional Withholding Tax with a tax credit for the corporate income tax paid the rights granted in the CEOP once it is signed, exploration and exploitation are by the contractor. With regard to the value added tax, contractors may obtain nonetheless subject to significant government regulations, such as regulations as a refund the value added tax (which is 19% according to the Sales and concerning the environment, tort liability, health and safety and labor. Services Tax Law contained in Decree Law No. 825 of 1974) supported or paid Regulatory framework on the import or purchase of goods or services used in connection with the exploration and exploitation activities. The applicable tax regime for each CEOP Regulation of exploration and production activities remains unchanged throughout the duration of the CEOP. Oil and gas exploration and development is governed by the Political Constitution of the Republic of Chile and Decree with Law Force No 2 of The Chilean Congress approved a reform to the income tax law in September 1986 of the Ministry of Mines, which set forth the revised text of the Decree 2014 which was amended in February 2016. Under this reform the income tax Law 1089 of 1975, on CEOPS. However, the right to explore and develop rate will increase from 20% in 2013 to: 21% in 2014, 22.5% in 2015, 24% in 2016, fields is granted for each area under a CEOP between Chile and the relevant 25.5% in 2017 and 27% in 2018. The operating subsidiaries that we control in contractors. The CEOP establishes the legal framework for hydrocarbon Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes activities, including, among other things, minimum investment commitments, Limitada, are not affected by the income tax reform mentioned since they are exploration and exploitation phase durations, compensation for the private covered by the tax treatment established in the CEOPs. The above has been company (either in cash or in kind) and the applicable tax regime. Accordingly, confirmed by the Chilean IRS through ruling N°2478/2016. all the provisions governing the exploitation and development of our Chilean operations are contained in our CEOPs and the CEOPs constitute all the Brazil licenses that we need in order to own, operate, import and export any of Regulation of the oil and gas industry the equipment used in our business and to conduct our gas and petroleum Article 177 of the Brazilian Federal Constitution of 1988 provides for the operations in Chile. Federal Government’s monopoly over the prospecting and exploration of oil, natural gas resources and other fluid hydrocarbon deposits, as well as over Under Chilean law, the surface landowners have no property rights over the refining, importation, exportation and sea or pipeline transportation of the minerals found under the surface of their land. Subsurface rights do not crude oil and natural gas. Initially, paragraph one of article 177 barred the generate any surface rights, except the right to impose legal easements or assignment or concession of any kind of involvement in the exploration rights of way. Easements or rights of way can be individually negotiated with of oil or natural gas deposits to private industry. On November 9, 1995, individual surface land owners or can be granted without the consent of the however, Constitutional Amendment Number 9 altered paragraph one of landowner through judicial process. Pursuant to the Chilean Code of Mines, a article 177 so as to allow private or state-owned companies to engage in the judge can permit a party to use an easement pending final adjudication and exploration and production of oil and natural gas, subject to the conditions settlement of compensation for the affected landowner. to be set forth by legislation. Taxation Regulatory framework With regard to indirect taxes on hydrocarbon exploitation, the general rule is Pricing policy that hydrocarbons are transferred to the contractor (its retribution under the Until the enactment of the Brazilian Petroleum Law, the Brazilian government CEOP), and those re-acquisitions from the contractor performed by Chile or regulated all aspects of the pricing of oil and oil products in Brazil, from the its enterprises, as well as their corresponding acts, contracts and documents, cost of oil imported for use in refineries to the price of refined oil products are tax exempt. In addition, hydrocarbon exports by the contractor are also charged to the consumer. Under the rules adopted following the Brazilian tax exempt. With regard to income taxes, as provided by article 5 of Decree Petroleum Law, the Brazilian government changed its price regulation policies. Law No. 1,089, the contractor is subject either to a single tax calculated on Under these regulations, the Brazilian government: (1) introduced a new its retribution, equal to 50% of such retribution, or to the general income tax methodology for determining the price of oil products designed to track regime established in the Income Tax Law (Decree Law No. 824 of 1974), in force prevailing international prices denominated in U.S. dollars, and (2) gradually at the time of the execution of the public deed which contains CEOPs, terms of eliminated controls on wholesale prices. which will be applicable and invariable throughout the duration of the contract. Income in Chile is subject to corporate tax on an accrual basis and has a current Concessions rate of 25.5% for fiscal year 2017. The applicable and invariable corporate In addition to opening the Brazilian oil and natural gas industry to private income tax rates of our CEOPs range between 15% and 18.5%, as follows: the investment, the Brazilian Petroleum Law created new institutions, including Fell Block is subject to a rate of 15%, the Tranquilo Block is subject to a rate of the ANP, to regulate and control activities in the sector. As part of this 17% and the Flamenco, Isla Norte and Campanario Blocks are subject to a rate mandate, the ANP is responsible for licensing concession rights for the of 18.5% for the income accrued or received during 2012 and 17% for exploration, development and production of oil and natural gas in Brazil’s GeoPark 101 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. Taxation Relevant Tax Aspects on Upstream Activities . The special customs regime for goods to be used in the oil and gas activities in Brazil, REPETRO, aims primarily The Brazilian Petroleum Law introduced significant modifications and benefits at reducing the tax burden on companies involved in exploring and extracting to the taxation of oil and natural gas activities. The main component of oil and natural gas, through the total suspension of federal taxes due on the petroleum taxation is the government take, comprised of license fees, fees importation of equipment (platforms, subsea equipment, among others), payable in connection with the occupation or title of areas, royalties and a under leasing agreements, subject to the compliance with applicable legal special participation fee. The introduction of the Brazilian Petroleum Law requirements. The period in which the goods are allowed to remain in Brazil presents certain tax benefits primarily with respect to indirect taxes. Such under the REPETRO regime may vary depending on the importer, but usually indirect taxes are very complex and can add significantly to project costs. Direct corresponds to the duration of the contract executed between the Brazilian taxes are mainly corporate income tax and social contribution on net profit. company and the foreign entity, or the period for which the company was authorized to exploit or produce oil and gas. Government take. With the effectiveness of the Brazilian Petroleum Law and the regulations promulgated by the ANP, concessionaires are required to pay In 2007, the legislation regarding the State Value Added Tax—ICMS imposed the Brazilian federal government the following: taxation on the import of equipment into Brazil under the REPETRO regime • license fees; was significantly changed by ICMS Convention No. 130/2007. This regulation • rent for the occupation or retention of areas; allows each State to grant the ICMS tax calculation basis reduction (generating • special participation fee; and • royalties on production. a tax burden of 7.5% with the recoverability of credits or 3%, without the recoverability of credits) for goods purchased under the REPETRO regime for the production phase and the total exemption or ICMS tax calculation basis The minimum value of the license fees is established in the bidding rules for reduction (generating a tax burden of 1.5%, without the recoverability of the concessions, and the amount is based on the assessment of the potential, credits) for the exploration phase. In order to be in force, the ICMS Convention as conducted by the ANP. The license fees must be paid upon the execution No. 130/07 must be included in each state’s legislation. 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 For example, currently, based on Convention No. 130/2007, the state of Rio de hydrocarbon production. Janeiro grants tax calculation basis reduction for the exploitation (generating a tax burden of 7.5%, with the recoverability of credits or 3%, without The special participation fee is an extraordinary charge that concessionaires the recoverability of credits) and production of oil and gas (generating a must pay in the event of obtaining high production volumes and/or tax burden of 1.5%, without the recoverability of credits). For production profitability from oil fields, according to criteria established by applicable activities, the legislation previously granted an exemption of ICMS, which regulation, and is payable on a quarterly basis for each field from the date on was changed to a tax calculation basis reduction, according to Resolution which extraordinary production occurs. This participation rate, whenever due, Sefaz No. 631, dated May 14, 2013. Taxpayers, however, have challenged this may reach up to 40% of net revenues depending on (i) volume of production change and received favorable decisions in court in order to avoid collecting and (ii) whether the block is onshore, shallow water or deep water. Under the ICMS on REPETRO imports as, according to STF (Supreme Court of Justice), the Brazilian Petroleum Law and applicable regulations issued by the ANP, the temporary imports on REPETRO do not constitute an ICMS triggering event. special participation fee is calculated based upon quarterly net revenues of each field, which consist of gross revenues calculated using reference prices It is important to mention that before the enactment of the Convention published by the ANP (reflecting international prices and the exchange rate No. 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on for the period) less: royalties paid; investment in exploration; operational costs; production activities, based on State Law No. 4,117, dated June, 27, 2003, and depreciation adjustments and applicable taxes. which was regulated by Decree No. 34,761, dated February 3, 2004, and was The ANP is responsible for determining monthly minimum prices for undetermined period of time. This legislation has been revoked in 2015 when petroleum produced in concessions for purposes of royalties payable with Rio de Janeiro State created Law No. 7,183/2015 aiming to collect ICMS on subsequently suspended by Decree No. 34,783 of February 4, 2004 for an 102 GeoPark 20-F the extraction of oil and Law No. 7,182/2015 creating a new fee per barrel and exploitation stage –when such discovery has not been made yet. In this of oil produced in the state. The constitutionality of these laws is currently case, the exploration phase will last no more than 7 years, counted from the being challenged by taxpayers. It is important to highlight that, while such effective date of the contract (60 days after the signing date). This term can legislation applies for oil fields operated in the State of Rio de Janeiro, be divided into several periods as agreed in the contract, and all of them legislation may vary in other states. with a minimum work obligation that should be fulfilled by a contractor in order to access the next exploration period. The exploration phase will last Pursuant to the Brazilian Petroleum Law and subsequent legislation, the until a declaration of commercial discovery is made by the contractor. The federal government enacted Law No. 10,336/01, to impose the Contribution exploitation phase will last from the date of such declaration until 30 years for Intervention in the Economic Sector, or CIDE, an excise tax payable by from the date of the contract. producers, blenders and importers on transactions with some oil and fuel products, which is imposed at a flat rate based on the specific quantities The Ministry of Energy and Mines may exceptionally authorize an extension of each product. Currently, the CIDE rates are zero, based on Decree No. of three years for the exploration stage, if the contractor has fulfilled with the 7,764/2012. minimum work program established in the contract, and also commits to fulfill an additional work program that justifies such extension. The contractor shall Brazil has enacted a corporate tax reform, Law 12.973 of 13 May 2014. On be responsible for providing the technical and economic resources required upstream operations, as from 2015 fiscal year, the new tax law may generate for the execution of the operations of this phase. timing effects for income tax purposes on the deduction of pre-operational costs as well as depreciation of fixed assets and amortization of intangibles. The Peruvian regulations also established the roles of the Peruvian The new law imposes restrictions for the tax deduction of goodwill arising government agencies that regulate, promote and supervise the oil and from in-house operations and brings several changes to the Brazilian CFC gas industry, including the Ministry of Energy and Mines, Perupetro and rules. Peru OSINERGMIN. Taxation Regulation of the oil and gas industry The fiscal regime that applies in Peru to the oil and gas industry consists of a The hydrocarbons activities in Peru are mainly regulated by the General combination of corporate income tax, royalties and other levies. Hydrocarbons Law (Law 26,221), and several regulations enacted in order to In general terms, oil and gas companies are subject to the general corporate develop the provisions included in such law. income tax regime that is stabilized in the applicable regime on the date of According to the Hydrocarbons Law, oil and gas exploration and production nevertheless, there are certain special tax provisions for the oil and gas sector. activities are carried out under license or service contracts granted by the Resident companies (incorporated in Peru), are subject to income tax on government. Under a license contract, the investor pays a royalty, whereas their worldwide taxable income. Branches and permanent establishments of under a service contract, the government pays remuneration to the contractor. foreign companies that are located in Peru and non-resident entities are taxed subscription of the original License Agreement (due to a tax stability contract); As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons, on Peruvian source income only. a license contract does not imply a transfer or lease of property over the area of exploration or exploitation. By virtue of the license contract, the With respect to the Morona Agreement, in which we take part, the applicable contractor acquires the authorization to explore or to exploit hydrocarbons income tax stabilized regime is from 1995, which is the year of subscription in a determined area, and Perupetro (the entity that holds the Peruvian state of the original License Agreement. The income tax rate in 1995 was 30% and interest) transfers the property right in the extracted hydrocarbons to the there was no withholding income tax for dividends. Additionally, in 1995 contractor, who must pay a royalty to the state. it was stated that the income tax should not be lower than 2% of the net Regulatory framework assets of the Company (the “Minimum Income Tax”). The Minimum Income Tax was later declared unconstitutional, which is why, even when there was a License and service contracts are approved by a supreme decree issued by tax stability contract, the Minimum Income Tax has been understood as not the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of applicable or enforceable. 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 Taxable income is generally computed by reducing gross revenue by cost of must be duly qualified by Perupetro, in order to determine if it fulfills all the goods sold and all expenses necessary to produce the income or maintain requirements needed to develop exploration and production activities under the source of income. Certain types of revenue, however, must be computed the contract form requirements mentioned above. as specified in the tax law and some expenses are not fully deductible for License and services agreements may be granted for just an exploitation tax purposes. Business transactions must be recorded in legally authorized stage -when a commercial discovery has been made- or for an exploration GeoPark 103 accounting records that are in full compliance with the International Exemptions are withdrawn at the production phase, but exceptions are made Accounting Standards (IAS). Contractors in a license or services contract for in certain instances, and the operator may be entitled to temporarily import the exploration or exploitation of hydrocarbons (Peruvian corporations and goods tax-free for a two-year period (“Temporary Import”). A temporary branches) are entitled to keep their accounting records in foreign currency, Import may be extended for additional one year periods for up to two times but taxes must be paid in Peruvian Nuevos Soles (“PEN”). upon the request of an operator, approval of the Ministry of Energy and Mines and authorization of the Superintendencia Nacional de Aduanas y de Any investments in a contract area that did not reach the commercial Administracion Tributaria (Peruvian Customs Agency). 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 Environmental Regulation stage of commercial extraction. Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling of exploration wells, etc.) the contractor must file and obtain an approval for These investments are amortized in accordance with the amortization method an Environmental Impact Study (EIS), which is the most important permit chosen by the contractor. If the contractor has entered into a single contract, related to HSE for any hydrocarbon project. This study includes technical, the accumulated investments are charged as a loss against the results of the environmental and social evaluations of the project to be executed in order contract for the year of total release of the area for any contract that did not to define the activities that should be required for preventing, minimizing, reach the commercial extraction stage, with the exception of investments mitigating and remediation of the possible negative environmental and social consisting of buildings, power installations, camps, means of communication, impacts that the hydrocarbon project may generate. equipment and other goods that the contractor keeps or recovers to use in the same operations or in other operations of a different nature. There are general environmental regulations for the protection of water, soils, air, endangered species, biodiversity, natural protected areas, etc. In addition, The contractor determines the tax base and the amount of the tax, separately there are specific environmental regulations applicable to the hydrocarbon and for each contract. If the contractor carries out related activities (i.e., industry. activities related to oil and gas, but not carried out under the terms of the contract) or other activities (i.e., activities not related to oil and gas), the Argentina contractor is obligated to determine the tax base and the amount of tax, Regulatory framework separately, and for each activity. The corresponding tax is determined based From the 1920s to 1989, the Argentine public sector dominated the upstream on the income tax provisions that apply in each case (subject to the tax segment of the Argentine oil and gas industry and the midstream and stability provisions for contract activities and based on the regular regime for downstream segment of the business. the related activities or other activities). The total income tax amount that the contractor must pay is the sum of the amounts calculated for each contract, In 1989, Argentina enacted certain laws aimed at privatizing the majority for both the related activities and for the other activities. The forms to be used of its state-owned companies and issued a series of presidential decrees for tax statements and payments are determined by the tax administration. (namely, Decrees No. 1055/89, 1212/89 and 1589/89 (the “Oil Deregulation Decrees”), relating specifically to deregulation of energy activities). The Oil If the contractor has more than one contract, it may offset the tax losses Deregulation Decrees eliminated restrictions on imports and exports of crude generated by one or more contracts against the profits resulting from other oil, deregulated the domestic oil industry, and effective January 1, 1991, the contracts or related activities. Moreover, the tax losses resulting from related prices of oil and petroleum products were also deregulated. In 1992, Law activities may be offset against the profits from one or more contracts. No. 24,145, referred to as the Privatization Law, privatized YPF and provided It is possible to choose the allocation of tax losses to one or more of the for transfer of hydrocarbon reservoirs from the Argentine government to the contracts or related activities that have generated the profits, provided that provinces, subject to the existing rights of the holders of exploration permits the losses are depleted or compensated to the limit of the profits available. and production concessions. This means that if there is another contract or related activity, the taxpayer can continue compensating tax losses until they are completely offset. A In October 2004, the Argentine Congress enacted Law No. 25,943, creating contractor with tax losses from one or more contracts or related activities may a new state-owned energy company, Energía Argentina S.A. (“ENARSA”). not offset them against profits generated by the other activities. Furthermore, The corporate purpose of ENARSA is the exploration and exploitation of in no case may tax losses generated by the other activities be offset against solid, liquid and gaseous hydrocarbons; the transport, storage, distribution, the profits resulting from the contracts or the related activities. commercialization and industrialization of these products; as well as the transportation and distribution of natural gas, and the generation, During the exploration phase, operators are exempt from import duties and transportation, distribution and sale of electricity. Moreover, Law No. 25,943 other forms of taxation applicable to goods intended for exploration activities. granted ENARSA all offshore areas located beyond 12 nautical miles from the 104 GeoPark 20-F coastline up to the outer boundary of the continental shelf that were vacant at conventional exploitation, unconventional exploitation, and exploitation in the time of the effectiveness of this law (i.e. November 3, 2004). the continental shelf and territorial waters, establishing the respective terms for each type. On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty • The terms for hydrocarbon transportation concessions were adjusted in order Act. This law declared achieving self-sufficiency in the supply of hydrocarbons, to comply with the exploitation concessions terms. as well as in the exploitation, industrialization, transportation and sale of • With regards to royalties, a maximum of 12% is established, which may reach hydrocarbons, a national public interest and a priority for Argentina. In 18% in the case of granted extensions, where the law also establishes the addition, the law expropriated 51% of the share capital of YPF, the largest payment of an extension bond for a maximum amount equal to the amount Argentine oil company, from Repsol, the largest Spanish oil company. resulting from multiplying the remaining proven reserves at the end of On July 28, 2012, Presidential Decree 1277/2012, which regulated the to the respective hydrocarbons over the 2 years preceding the time on which Hydrocarbon Sovereignty Law, was released, creating a Strategic Planning and the extension was granted. Coordination Committee for the National Hydrocarbon Investment Plan and • The extension of the Investment Promotion Regime for the Exploitation of vesting it with the power to set the sector’s reference prices and to develop Hydrocarbons (Decree No. 929/2013) is established for projects representing investment plans for the country to increase production and reserves. The a direct investment in foreign currency of at least 250 million dollars, effective term of the concession by 2% of the average basin price applicable decree introduced important changes to the rules governing Argentina’s increasing the benefits for other type of projects. oil and gas industry, including the repeal of certain articles of Deregulation Decrees passed during 1989 relating to free marketability of hydrocarbons Regulation of transportation activities at negotiated prices, the deregulation of the oil and gas industry, freedom to Exploitation concessionaires have the exclusive right to obtain a import and export hydrocarbons and the ability to keep proceeds from export transportation concession for the transport of oil and gas from the provincial sales in foreign bank accounts. states or the federal government, depending on the applicable jurisdiction. Such transportation concessions include storage, ports, pipelines and other On January 4, 2016, immediately after the new national administration took fixed facilities necessary for the transportation of oil, gas and by-products. office, Presidential Decree 272/2015 was released. This Decree abrogated Transportation facilities with surplus capacity must transport third parties’ the provisions of the Presidential Decree 1277/2012 which had repealed the hydrocarbons on an open-access basis, for a fee which is the same for all users Deregulation Decrees. Thus, the Deregulation Decrees were reinstated. on similar terms. As a result of the privatizations of YPF and Gas del Estado, a Other measures have also been taken by the new presidential administration few common carriers of crude oil and natural gas were chartered and continue aimed at reducing government intervention and reestablishing market forces to operate to date. in the oil & gas industry. Taxation Domain and Jurisdiction of hydrocarbons resources Exploitation concessionaires are subject to the general federal and provincial After a constitutional reform enacted in 1994, eminent domain over tax regime. The most relevant federal taxes are the income tax (35%), the value hydrocarbon resources lying in the territory of a provincial state is now vested added tax (21%) and a tax on assets. The most relevant provincial taxes are the in such provincial state, while eminent domain over hydrocarbon resources turnover tax (1% to 3%) and stamp tax. In 2002, in response to the economic lying offshore on the continental platform beyond the jurisdiction of the crisis, the federal government adopted new taxes on oil and gas products, coastal provincial states is vested in the federal state. including export taxes ranging from 5% for by-products to 45% for crude oil. Such export taxes lapsed and terminated on January 6, 2016 on the 15th Thus, oil and gas exploration permits and exploitation concessions are now anniversary of their enactment. granted by each provincial government. A majority of the existing concessions were granted by the federal government prior to the enactment of Law Tax reform has been enacted in Argentina during December 2017. The No.26,197 and were thereafter transferred to the provincial states. legislation included significant changes to certain corporate income tax and statutory income tax provisions, including rate reductions. Most of the tax Regulation of exploration and production activities provisions are 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%. will of Law No. 27,007, amending the Hydrocarbon Law No. 17,319. have the following rate schedule: The most relevant aspects of the new law are as follows: • 25% in 2020 and 2021 and onwards. • With regards to concessions, three types of concessions are provided, namely, Other changes include the following: • 30% in 2018 and 2019 • New withholding tax on dividends—with the applicable rates for GeoPark 105 Operating and financial review and prospects non-resident shareholders of: (1) 7% for dividends distributed out of the (including through bidding rounds) or gaining access to oil and natural distributing entity’s previously taxed profits of fiscal years 2018 and 2019; and gas reserves. While we have geological reports evaluating certain proved, (2) 13% for dividends distributed out of the distributing entity’s previously contingent and prospective resources in our blocks, there is no assurance that taxed profits of fiscal years 2020 and onwards. we will continue to be successful in the exploration, appraisal, development • Application of inflation adjustment for corporate tax purposes is reinstated and commercial production of oil and natural gas. The calculation of our under certain circumstances. geological and petrophysical estimates is complex and imprecise, and it is • Possible tax revaluation of investment in fixed assets, under payment of a possible that our future exploration will not result in additional discoveries, special tax. 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, 2017, we made total capital expenditures of US$105.6 million (US$80.0 million, US$10.2 million, US$8.2 million, US$3.6 We are an exempted company incorporated pursuant to the laws of Bermuda. million and US$3.6 million in Colombia, Chile, Argentina, Peru and Brazil, We operate and own our assets directly and indirectly through a number respectively), consisting of US$49.5 million related to exploration. of subsidiaries. See an illustration of our corporate structure in Note 21 (“Subsidiary undertakings”) to our Consolidated Financial Statements. During Oil prices were volatile since the end of 2014. In preparation for continued 2017, we decided to incorporate a subsidiary in the United Kingdom to volatility, we have developed multiple scenarios for our 2018 capital conduct our businesses in Latin America by adopting all the key resolutions expenditure program. See “Item 4. Information on the Company –B. Business and decisions necessary for such purpose. In addition, as a result of tax reform Overview—2018 Strategy and Outlook.” enacted in the Netherlands during 2017, we decided to re-domicile our 100% owned Dutch subsidiaries to Spain. D. Property, plant and equipment Funding for our capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity See “—B. Business Overview—Title to properties.” and the covenants in our financing agreements, as well as the amount of cash ITEM 4A. UNRESOLVED STAFF COMMENTS are able to generate from current operations and the amount of cash we can we can borrow using our oil reserves as collateral, the amount of cash we Not applicable. obtain from prepayment agreements such as the Trafigura Agreement, which is our offtake and prepayment agreement. If we are not able to generate ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS the sales which, together with our current cash resources, are sufficient to A. Operating results fund our capital program, we will not be able to efficiently execute our work program which would cause us to further decrease our work program, which could harm our business outlook, investor confidence and our share price. The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements If oil prices average higher than the base budget price, we have the ability and the notes thereto as well as the information presented under “Item 3. Key to allocate additional capital to more projects and increase its work and Information— A. Selected financial data.” investment program and thereby further increase oil and gas production. The following discussion contains forward-looking statements that involve risks Our results of operations will be adversely affected in the event that our and uncertainties. Our actual results may differ materially from those discussed estimated oil and natural gas asset base does not result in additional reserves in the forward-looking statements as a result of various factors, including those that may eventually be commercially developed. In addition, there can be set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking no assurance that we will acquire new exploration blocks or gain access to statements.” exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our Factors affecting our results of operations anticipated reserves will continually decrease, which would have a material We describe below the year-to-year comparisons of our historical results and adverse effect on our business, results of operations and financial condition. the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following: Oil and gas revenue and international prices Discovery and exploitation of reserves as well as of condensate derived from the production of natural gas. The Our results of operations depend on our level of success in finding, acquiring price realized for the oil we produce is generally linked to Brent or Vasconia. Our revenues are derived from the sale of our oil and natural gas production, 106 GeoPark 20-F The price realized for the natural gas we produce in Chile is linked to the year ended December 31, 2017 would have been higher by US$10.4 million international price of methanol, which is settled in the international markets (US$23.7 million in 2016). in US$. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively In Brazil, prices for gas produced in the Manati Field are based on a long-term minor changes in the global supply and demand for oil and natural gas, off-take contract with Petrobras. The price of gas sold under this contract is market uncertainty, economic conditions and a variety of additional factors. denominated in reais and is adjusted annually for inflation pursuant to the From January 1, 2013 to December 31, 2017, Brent spot prices ranged from a Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the low of US$27.9 per barrel to a high of US$118.9 per barrel, Henry Hub natural “IGPM”). See Note 3 to our Consolidated Financial Statements. gas average spot prices ranged from a low of US$1.7 per mmbtu to a high of US$6.0 per mmbtu, US Gulf methanol spot barge prices ranged from a low of Production and operating costs US$250.0 per metric ton to a high of US$635.1 per metric ton. Furthermore, Our production and operating costs consist primarily of expenses associated oil, natural gas and methanol prices do not necessarily fluctuate in direct with the production of oil and gas, the most significant of which are gas relationship to each other. plant leasing, facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties and As a consequence of the oil price crisis which started in the second half of products, among others. As commodity prices increase or decrease, our 2014 (WTI and Brent, the main international oil price markers, fell more than production costs may vary. We have historically not hedged our costs to 60% between October 2014 and February 2016), we took decisive steps in protect against fluctuations. 2015 and 2016 to adapt to the new oil price environment. We reduced our capital expenditure program from US$238 million in 2014 to US$48 million in Availability and reliability of infrastructure 2015 and US$39 million in 2016 and implemented significant cost reduction Our business depends on the availability and reliability of operating and initiatives that resulted in production and operating costs being reduced by transportation infrastructure in the areas in which we operate. Prices and 49% (2016 versus 2014), and administrative expenses being reduced by 26% availability for equipment and infrastructure, and the maintenance thereof, (2016 versus 2014), while increasing average production to approximately 22.4 affect our ability to make the investments necessary to operate our business, mboepd and increasing our proved reserves to 73.6 mmboe. and thus our results of operations and financial condition. See “Item 3. Key In October 2016, we decided to manage part of our exposure to the volatile Information—D. Risk factors—Risks relating to our business—Our inability to crude oil price using derivatives. For further information related to Commodity access needed equipment and infrastructure in a timely manner may hinder Risk Management Contracts, please see Note 8 to our Consolidated Financial our access to oil and natural gas markets and generate significant incremental Statements. costs or delays in our oil and natural gas production.” Additionally, the oil and gas we sell may be subject to certain discounts. For In order to mitigate the risk of unavailability of operating and transportation example, in Colombia, the price of oil we sell is based on Vasconia, a marker infrastructure, we have invested in the construction of plant and pipeline broadly used in the Llanos Basin, adjusted for certain marketing and quality infrastructure to produce, process and store hydrocarbon reserves and to discounts based on, among other things, API, viscosity, sulfur, delivery point transport them to market. and water content, as well as on certain transportation costs (including pipeline costs and trucking costs). Production levels Our oil and gas production levels are heavily influenced by our drilling results, In Chile, the price of oil we sell to ENAP is based on Brent minus certain our acquisitions and to oil and natural gas prices. marketing and quality discounts. We have a long-term gas supply contract with Methanex. The price of the gas sold under this contract is determined We expect that fluctuations in our financial condition and results of operations based on a formula that takes into account various international prices of will be driven by the rate at which production volumes from our wells decline. methanol, including US Gulf methanol spot barge prices, methanol spot As initial reservoir pressures are depleted, oil and gas production from a given Rotterdam prices and spot prices in Asia. See “Item 3. Key Information—D. Risk well will decline over time. See “Item 3. Key Information—D. Risk factors— factors—Risks relating to our business—A substantial or extended decline Risks relating to our business—Unless we replace our oil and natural gas in oil, natural gas and methanol prices may materially adversely affect our reserves, our reserves and production will decline over time. Our business is business, financial condition or results of operations.” dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not If the market prices of oil and methanol had fallen by 10% as compared to yield oil or natural gas in commercial quantities.” actual prices during the year, with all other variables held constant, taking into account the impact of the derivative contracts in place, post-tax loss for the Contractual obligations In order to protect our exploration and production rights in our license GeoPark 107 areas, we must make and declare discoveries within certain time periods Description of principal line items specified in our various special contracts, E&P Contracts and concession The following is a brief description of the principal line items of our statement agreements. The costs to maintain or operate our license areas may fluctuate of income. or increase significantly, and we may not be able to meet our commitments under these agreements on commercially reasonable terms or at all, which Revenue may force us to forfeit our interests in such areas. If we do not succeed in Revenue includes the sale of crude oil, condensate and natural gas net of renewing these agreements, or in securing new ones, our ability to grow value-added tax (“VAT”), and discounts related to the sale (such as API and our business may be materially impaired. See “Item 3. Key Information—D. mercury adjustments) and overriding royalties due to the ex-owners of oil Risk factors—Risks relating to our business—Under the terms of some of our and gas properties where the royalty arrangements represent a retained various CEOPs, E&P Contracts and concession agreements, we are obligated working interest in the property. Revenue is recognized when the significant to drill wells, declare any discoveries and file periodic reports in order to risks and rewards of ownership have been transferred to the buyer, the retain our rights and establish development areas. Failure to meet these associated costs and amount of revenue can be estimated reliably, recovery obligations may result in the loss of our interests in the undeveloped parts of the consideration is probable, and there is no continuing management of our blocks or concession areas.” involvement with the goods. Acquisitions Commodity risk management contracts Our results of operations are significantly affected by our past acquisitions. We Includes realized and unrealized gains and losses arising from commodity risk generally incorporate our acquired business into our results of operations at management contracts. or around the date of closing, such as our Colombian acquisitions in 2012 and our Rio das Contas acquisition in 2014, which limits the comparability of the Production and operating costs period including such acquisitions with prior or future periods. For a description of our production and operating costs, see “—Factors affecting our results of operations.” As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, Depreciation and write-off of unsuccessful efforts producing properties and concessions. As with our historical acquisitions, Capitalized costs of proved oil and natural gas properties are depreciated on any future acquisitions could make year-to-year comparisons of our results of a licensed-area-by-licensed-area basis, using the unit of production method, operations difficult. We may also incur additional debt, issue equity securities based on commercial proved and probable reserves as calculated under the or use other funding sources to fund future acquisitions. Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), Functional and presentational currency which differs from SEC reporting guidelines pursuant to which certain Our Consolidated Financial Statements are presented in US$, which is our information in the forepart of this annual report is presented. The calculation functional and presentational currency. Items included in the financial of the “unit of production” depreciation takes into account estimated future information of each of our entities are measured using the currency of the discovery and development costs. Changes in reserves and cost estimates are primary economic environment in which the entity operates, or the functional recognized prospectively. Reserves are converted to equivalent units on the currency, which is the US$ in each case, except for our Brazil operations, where basis of approximate relative energy content. the functional currency is the real. Geographical segment reporting In particular, upon completion of the evaluation phase, a prospect is either transferred to oil and gas properties if it contains reserves, or is charged to In the description of our results of operations that follow, our “Other” profit and loss in the period in which the determination is made. See “— operations reflect our non-Colombian, non-Chilean and non-Brazilian Critical accounting policies and estimates—Oil and gas accounting.” operations, primarily consisting of our Argentine, Peruvian (mainly related to the start-up of our operations in such country) and corporate head office Geological and geophysical expenses operations. Geological and geophysical expenses consist of geosciences costs, including wages and salaries and share-based compensation not subject to We divide our business into five geographical segments—Colombia, Chile, capitalization, geological consultancy costs and costs relating to independent Brazil, Peru and Argentina—that correspond to our principal jurisdictions of reservoir engineer studies. operation. Activities not falling into these four geographical segments are Administrative expenses reported under a separate corporate segment that primarily includes certain Administrative costs consist of corporate costs such as director fees corporate administrative costs not attributable to another segment. and travel expenses, new project evaluations and back-office expenses 108 GeoPark 20-F principally comprised of wages and salaries, share-based compensation, of contingent assets and liabilities. We continually evaluate these estimates consultant fees and other administrative costs, including certain costs and assumptions based on the most recently available information, our own relating to acquisitions. historical experience and various other assumptions that we believe to be reasonable under the circumstances. Since the use of estimates is an integral Our administrative expenses for the year ended December 31, 2017 component of the financial reporting process, actual results could differ increased by US$7.9 million, or 23%, compared to the year ended December from those estimates. 31, 2016 mainly due to higher staff costs resulting from increased scale of operations. However, administrative costs may increase as a result of our An accounting policy is considered critical if it requires an accounting Peruvian and Argentinian operations, other acquisitions, increased activity estimate to be made based on assumptions about matters that are highly or the impact of appreciation of local currencies in the countries where we uncertain at the time such estimate is made, and if different accounting operate. Selling expenses estimates that reasonably could have been used, or changes in the accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following Selling expenses consist primarily of transportation and storage costs. accounting policies represent critical accounting policies as they involve a Impairment of non-financial assets higher degree of judgment and complexity in their application and require us to make significant accounting estimates. The following descriptions of Assets that are not subject to depreciation and/or amortization (such as critical accounting policies and estimates should be read in conjunction exploration and evaluation assets) are tested annually for impairment. with our Consolidated Financial Statements and the accompanying notes Assets that are subject to depreciation and/or amortization are reviewed for and other disclosures. impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Business combinations Business combinations are accounted for using the acquisition method. An impairment loss is recognized for the amount by which the asset’s carrying The cost of an acquisition is measured as the fair market value of the assets amount exceeds its recoverable amount. The recoverable amount is the higher acquired, equity instruments issued and liabilities incurred or assumed on the of an asset’s fair value minus costs to sell and value in use. date of completion of the acquisition. Acquisition costs incurred are expensed During 2017, we did not recognize an additional impairment, while in 2016 we liabilities and contingent liabilities assumed in a business combination are recognized a reversal of impairment losses of US$5.7 million and in 2015 we measured initially at their fair market values at the acquisition date. The recognized impairment losses amounting to US$149.6 million. See Note 36 to excess of the cost of acquisitions over fair market value of a company’s share and included in administrative expenses. Identifiable assets acquired and our Consolidated Financial Statements. Financial costs Financial costs consist of financial income offset by financial expenses. of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than a company’s share of the net assets required, the difference is recognized directly in the statement of income. Financial income includes interest received from bank time deposits. Financial The determination of fair value of identifiable acquired assets and assumed expenses principally include interest expense not subject to capitalization, liabilities means that we are to make estimates and use valuation techniques, bank charges and the unwinding of long-term liabilities. including independent appraisers. The valuation assumptions underlying Foreign exchange gain or loss each of these valuation methods are based on available updated information, including discount rates, estimated cash flows, market risk rates and other Foreign exchange gain or loss represents the effect of exchange rate differences. data. As a result, the process of identification and the related determination of fair values require complex judgments and significant estimates. Loss or profit for the period attributable to owners of the Company Loss or profit for the period attributable to owners of the Company consists of Cash flow estimates for impairment assessments losses or profit for the year less non-controlling interest. Cash flow estimates for impairment assessments require assumptions about two primary elements: future prices and reserves. Estimates of Critical accounting policies and estimates future prices require significant judgments about highly uncertain future We prepare our Consolidated Financial Statements in accordance with IFRS events. Historically, oil and natural gas prices have exhibited significant and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as volatility. Our forecasts for oil and natural gas revenues are based on prices adopted by the IASB. The preparation of the financial statements requires derived from future price forecasts among industry analysts, as well as our us to make judgments, estimates and assumptions that affect the reported own assessments. Estimates of future cash flows are generally based on amounts of assets, liabilities, revenue and expenses, and related disclosure assumptions of long-term prices and operating and development costs. GeoPark 109 The process of estimating reserves requires significant judgments and Workovers of wells made to develop reserves and/or increase production decisions based on available geological, geophysical, engineering and are capitalized as development costs. Maintenance costs are charged to economic data. The estimation of economically recoverable oil and natural gas income when incurred. reserves and related future net cash flows was performed based on the D&M Reserves Report. Such estimates incorporate many factors and assumptions Capitalized costs of proved oil and gas properties and production facilities including: and machinery are depreciated on a licensed area by licensed area basis, • expected reservoir characteristics based on geological, geophysical and using the unit of production method, based on commercial proved and engineering assessments; probable reserves. The calculation of the “unit of production” depreciation • future production rates based on historical performance and expected future takes into account estimated future finding and development costs, and is operating and investment activities; based on current year-end un-escalated price levels. Changes in reserves • future oil and natural gas prices and quality differentials; and cost estimates are recognized prospectively. Reserves are converted to • anticipated effects of regulation by governmental agencies; and equivalent units on the basis of approximate relative energy content. • future development and operating costs. Oil and gas reserves for purposes of our Consolidated Financial Statements are determined in accordance with PRMS, and were estimated by DeGolyer Our management believes these factors and assumptions are reasonable and MacNaughton, independent reserves engineers. based on the information available at the time we prepare our estimates. However, these estimates may change substantially as additional data from Depreciation of the remaining property, plant and equipment assets (i.e., ongoing development activities and production performance becomes furniture and vehicles) not directly associated with oil and gas activities available and as economic conditions impacting oil and natural gas prices has been calculated by means of the straight line method by applying and costs change. 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. For further information related to impairment of property, plant and equipment, please see Note 36 to our Consolidated Financial Statements. Asset retirement obligations Oil and gas accounting Obligations related to the plugging and abandonment of wells once operations are terminated may result in the recognition of significant liabilities. We record Oil and gas exploration and production activities are accounted for in the fair value of the liability for asset retirement obligations in the period in accordance with the successful efforts method on a field by field basis. which the wells are drilled. When the liability is initially recognized, the cost is We account for exploration and evaluation activities in accordance with also capitalized by increasing the carrying amount of the related asset. Over IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing time, the liability is accreted to its present value at each reporting date, and the exploration and evaluation costs until such time as the economic viability capitalized cost is depreciated over the estimated useful life of the related asset. of producing the underlying resources is determined. Costs incurred prior Estimating the future abandonment costs is difficult and requires management to obtaining legal rights to explore are expensed immediately to the to make assumptions and judgments because most of the obligations will be income statement. settled after many years. Technologies and costs are constantly changing, as are political, environmental, health, safety and public relations considerations. Exploration and evaluation costs may include: license acquisition, Consequently, the timing and future cost of dismantling and abandonment geological and geophysical studies (i.e., seismic), direct labor costs and are subject to significant modification. Any change in the variables underlying drilling costs of exploratory wells. No depreciation and/or amortization are our assumptions and estimates can have a significant effect on the liability charged during the exploration and evaluation phase. Upon completion and the related capitalized asset and future charges related to the retirement of the evaluation phase, the prospects are either transferred to oil and gas obligations. The present value of future costs necessary for well plugging and properties or charged to expense in the period in which the determination abandonment is calculated for each area at the present value of the estimated is made, depending whether they have found reserves. If not developed, future expenditure. The liability recognized is based upon estimated future exploration and evaluation assets are written off after three years, unless abandonment costs, wells subject to abandonment, time to abandonment, and it can be clearly demonstrated that the carrying value of the investment future inflation rates. is recoverable. All field development costs are considered construction in progress until they are finished and capitalized within oil and gas Share-based payments properties, and are subject to depreciation once completed. Such costs We provide several equity-settled, share-based compensation plans to certain may include the acquisition and installation of production facilities, employees and third-party contractors, composed of payments in the form of development drilling costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties. 110 GeoPark 20-F share awards and stock options plans. commercial, environmental and health & safety matters. For example, from time to time, the Company receives notices of environmental, health and safety Fair value of the stock option plans for employee or contractor services violations. Based on what our Management currently knows, such claims are received in exchange for the grant of the options is recognized as an expense. not expected to have a material impact on the financial statements. The total amount to be expensed over the vesting period, which is the period over which all specified vesting conditions are to be satisfied, is determined Recent accounting pronouncements by reference to the fair value of the options granted calculated using the See Note 2.1.1 to our Consolidated Financial Statements. Geometric Brownian Motion method. Determining the total value of our share-based payments requires the use of highly subjective assumptions, Results of operations including the expected life of the stock options, estimated forfeitures The following discussion is of certain financial and operating data for the and the price volatility of the underlying shares. The assumptions used in periods indicated. You should read this discussion in conjunction with our calculating the fair value of share-based payment represent management’s Consolidated Financial Statements and the accompanying notes. best estimates, but these estimates involve inherent uncertainties and the As a consequence of the oil price crisis which started in the second half of application of management’s judgment. 2014 (WTI and Brent, the main international oil price markers, fell more than 60% between August 2014 and March 2016), we have undertaken decisive Non-market vesting conditions are included in assumptions in respect of measures to ensure our ability to both maximize the work program and the number of options that are expected to vest. At each balance sheet date, preserve our cash. we revise our estimates of the number of options that are expected to vest. We recognize the impact of the revision to original estimates, if any, in the During 2015 and 2016, we took decisive steps to adapt to the new oil statement of income, with a corresponding adjustment to equity. price environment. We reduced our capital expenditure program from The fair value of the share awards payments is determined at the grant date by US$238 million in 2014 to US$48 million in 2015 and US$39 million in 2016 reference of the market value of the shares and recognized as an expense over and implemented significant cost reduction initiatives that resulted in the vesting period. production and operating costs being reduced by 49% (2016 versus 2014), and administrative expenses being reduced by 26% (2016 versus 2014), while When options are exercised, we issue new common shares. The proceeds increasing average production to approximately 22.4 mboepd and increasing received net of any directly attributable transaction costs are credited to share our proved reserves to 73.6 mmboe. For 2017, we designated a self-funded capital (nominal value) and share premium when the options are exercised. program that could be adapted to and provide production growth in different Taxation oil price scenarios. The main focus of the 2017 work program was to unlock the potential of the Tigana/Jacana oil field complex with a drilling program for The computation of our income tax expense involves the interpretation of 20 wells and new facility construction. 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 2018 capital expenditure program. See “Item 4. Information on the difficult to predict the ultimate outcome. Company –B. Business Overview—2018 Strategy and Outlook.” In addition, we have tax-loss carry-forwards in certain taxing jurisdictions Year ended December 31, 2017 compared to year ended December 31, 2016 that are available to offset against future taxable profit. However, deferred The following table summarizes certain of our financial and operating data for tax assets are recognized only to the extent that it is probable that taxable the years ended December 31, 2017 and 2016. profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. 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, GeoPark 111 For the year ended December 31 (in thousands of US$, except for percentages) (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 % Change foreign operations and the attendant royalty regimes. Oil production figures 2017 2016 prior year from presented on page F-76 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. 145,193 47,477 192,670 (2,554) (67,235) (10,282) (34,170) (4,222) (75,774) (31,366) 5,664 (1,344) (28,613) (34,101) 13,872 (48,842) (11,804) (60,646) (11,554) (49,092) 6,189 11,911 8,174 22,394 25.6 4.5 7.3 1.5 8.8 1.3 4.5 0.6 92% Gas production presented on page F-77 is gas measured at the point of 7% delivery. 71% 505% 47% (25)% 23% (73)% (1)% (81)% (100)% 279% (376)% 51% (116)% (152)% 266% (71)% (155)% (51)% 34% (11)% 23% 23% 43% 18% 1% 100% 18% (38)% (2)% (83)% Revenue Net oil sales Net gas sales Revenue 279,162 50,960 330,122 Commodity risk management contracts (15,448) Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful 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 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 ) Average unit costs per boe (US$) Operating cost Royalties and other Production costs(1) Geological and geophysical expenses Administrative expenses Selling expenses (98,987) (7,694) (42,054) (1,136) (74,885) (5,834) - (5,088) 78,996 (51,495) (2,193) 25,308 (43,145) (17,837) 6,391 (24,228) 8,309 10,562 10,069 27,586 36.6 5.3 7.4 3.0 10.4 0.8 4.4 0.1 112 GeoPark 20-F The following table summarizes certain financial and operating data. For the year ended December 31, (in thousands of US$) Chile Colombia 32,738 (23,730) 263,076 (40,010) Brazil 34,238 (10,809) Other 70 (336) 2017 Total 330,122 (74,885) Chile Colombia 36,723 (31,355) 126,228 (31,148) Brazil 29,719 (12,974) Other - (297) 2016 Total 192,670 (75,774) (546) (1,625) (2,978) (685) (5,834) (19,389) (1,730) (4,583) - (25,702) Revenue Depreciation Impairment and write-off Revenue For the year ended December 31, 2017, crude oil sales were our principal December 31, 2017 due to increased sales volumes and higher realized prices. source of revenue, with 85% and 15% of our total revenue from crude oil The increase in 2017 net revenue of US$137.5 million is mainly explained by: and gas sales, respectively. The following chart shows the change in oil and • an increase of US$136.8 million in sales in Colombia, due to an increase in natural gas sales from the year ended December 31, 2016 to the year ended price and volume; December 31, 2017. • a decrease of US$4 million in sales in Chile, including decreases of US$2.9 For the year ended December 31, million in oil sales and US$1.1 million of gas sales; and (in thousands of US$) • an increase of US$4.3 million in gas sales in Brazil, related to our Manati Consolidated Sale of crude oil Sale of gas Total By country Colombia Chile Brazil Other Total 2017 2016 operations; all of which was due principally to higher oil and gas prices, as further 279,162 50,960 described below. 145,193 47,477 Revenue attributable to our operations in Colombia for the year ended 330,122 192,670 December 31, 2017 was US$263.1 million, compared to US$126.2 million for the year ended December 31, 2016, representing 80% and 66% of our total consolidated sales. The increase is related to an increase in oil deliveries from Year ended December 31 Change from prior year 5.4 mmbbl to 7.6 mmbbl and an increase in the average realized price per (in thousands of US$, except for percentages) barrel of crude oil from US$24.4 per barrel to US$36.1 per barrel, primarily due 2017 2016 % 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 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 of as a result of higher oil revenues. Sales of crude oil increased due to higher crude oil from US$37.0 per barrel for the year December 31, 2016 to US$45.7 realized prices and higher sold volumes of 7.9 mmbbl in the year ended per barrel for the year ended December 31, 2017 (an increase of US$8.7 per December 31, 2017 compared to 5.9 mmbbl in the year ended December barrel or a total of 24%). The increase in the average realized price per barrel 31, 2016, and resulted in net revenue of US$279.2 million for the year ended was attributable to higher international reference prices. The contribution to December 31, 2017 compared to US$145.2 million for the year ended our revenue during such years from our operations in Chile was 10% and 19%, December 31, 2016. In addition, sales of gas increased from US$47.5 million respectively. for the year ended December 31, 2016 to US$51.0 million for the year ended GeoPark 113 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 Consolidated production and operating costs increased 47%, from US$67.2 million for the year ended December 31, 2016 to US$99.0 million for the year ended December 31, 2017, primarily due to higher royalties paid in cash, in line with increased production (the Jacana oil field accumulated more than 5 mmbbl during the year ended December 31, 2017, triggering a higher royalty rate in Colombia), and higher oil prices, and increased operating costs related to higher sales volumes. 114 GeoPark 20-F Year ended December 31 (in thousands of US$) 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) Production and operating costs in Colombia increased 83%, to US$66.9 million Administrative costs increased 23%, from US$34.2 million for the year ended for the year ended December 31, 2017, as compared to US$36.6 million for the December 31, 2016 to US$42.1 million for the year ended December 31, year ended December 31, 2016, primarily due to (i) higher royalties of US$17.0 2017, mainly due to higher staff costs and consulting fees resulting from an million, in line with increased production (the Jacana oil field accumulated increased scale of operations. 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 Selling expenses 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 Year ended December 31, Change from prior year Block. In addition, operating costs per boe in Colombia increased to US$5.6 per boe for the year ended December 31, 2017 from US$5.4 per boe for the year ended December 31, 2016. 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 per boe from US$15.8 per boe in 2016. In the year ended December 31, 2017, the revenue mix for Chile was 48.5% oil and 51.5% gas, whereas for the same Colombia Chile Brazil Other Total (in thousands of US$, except for percentages) 2017 (250) (688) - (198) (1,136) 2016 (2,830) (994) (20) (378) 2,580 306 20 180 (4,222) 3,086 % (91)% (31)% (100)% (48)% (73)% period in 2016 it was 51.1% oil and 48.9% gas. Selling expenses decreased 73%, from US$4.2 million for year ended December Production and operating costs in Brazil increased by 27%, to US$10.7 million due to the Trafigura offtake agreement as sales occur at the wellhead in our for the year ended December 31, 2017, as compared to the year ended Colombian operations, which are recorded as a discount to the oil price. 31, 2016 to US$1.1 million for the year ended December 31, 2017, primarily December 31, 2016, mainly resulting from non-recurring maintenance costs in Manati Field. Operating costs per boe increased to US$7.8 for the year ended Commodity risk management contracts December 31, 2017 from US$5.8 per boe for the year ended December 31, We recorded a loss of US$15.4 million related to commodity risk management 2016. contracts for the year ended December 31, 2017. Realized losses reflect cash settled transactions and unrealized losses reflect non-cash changes between the Geological and geophysical expenses contract values and the forward Brent oil curve. Year ended December 31 Change from prior year Depreciation (in thousands of US$, except for percentages) Depreciation charges decreased by 1% from US$75.8 million for the year ended 2017 (2,231) (858) (1,007) (3,598) 2016 (4,296) (1,671) (1,053) (3,262) (7,694) (10,282) 2,065 813 46 (336) 2,588 % December 31, 2016 to US$74.9 million for the year ended December 31, 2017, mainly due to lower production levels in Chile and Brazil. and lower depreciation costs per barrel in Colombia. Depreciation costs per boe decreased from US$9.9 to US$7.9 per boe. (48)% (49)% (4)% 10% (25)% Operating profit (loss) Colombia Chile Brazil Other Total Geological and geophysical expenses decreased 25%, from US$10.3 million for the year ended December 31, 2016 to US$7.7 million for the year ended December 31, 2017, primarily as the result of higher allocation to capitalized projects due to increased drilling activity levels. Administrative costs Year ended December 31 Change from prior year (in thousands of US$, except for percentages) Year ended December 31, Change from prior year (in thousands of US$, except for percentages) 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) % 270% (56)% (789)% 52% (28,613) 107,609 (376)% Colombia Chile Brazil Other Total Colombia (17,567) (14,715) (2,852) 19% December 31, 2017, a 376% improvement from the operating loss of 2017 2016 % We recorded an operating profit of US$79.0 million for the year ended 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) (11)% (21)% 70% 23% US$28.6 million for the year ended December 31, 2016, primarily due to an increase in revenue and other gains and a decrease in certain expenses GeoPark 115 and depreciation, as described above. In 2016, we recorded a gain on non- Loss Profit for the year cash impairments reversal of non-financial assets amounting to US$5.7 million in Colombia, resulting from an improved oil price environment and improvements in cost structure. Financial costs Financial costs increased 51% to US$51.5 million for the year ended December 31, 2017 as compared to US$34.1 million for the year ended December 31, 2016, mainly due to one-time costs on the cancellation of 2020 Notes for an amount of US$17.6 million. Colombia Chile Brazil Other Total Year ended December 31 Change from prior year (in thousands of US$, except for percentages) 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 % 387% (43)% (142)% 107% (71)% Foreign exchange (loss) gain For the year ended December 31, 2017, we recorded a net loss of US$17.8 Foreign exchange variation decreased from a gain of US$13.9 million for the million as a result of the reasons described above. 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 Loss Profit for the year attributable to owners of the Company real in the 2016 period and its depreciation in the 2017 period. Foreign Loss for the year attributable to owners of the Company decreased by 51% exchange differences are mainly generated from changes in the value of the to US$24.2 million, compared to a loss for the year ended December 31, Brazilian real over the U.S. Dollar-denominated debt incurred at the local 2016 of US$49.1 million for the reasons described above. Profit attributable subsidiary level, where the functional currency is the Brazilian real. to non-controlling interest increased by 155% to US$6.4 million for the year ended December 31, 2017 as compared to a loss of US$11.6 million for the Profit (Loss) before income tax year ended December 31, 2016. Year ended December 31 Change from prior year Year ended December 31, 2016 compared to year ended December 31, 2015 (in thousands of US$, except for percentages) The following table summarizes certain of our financial and operating data for 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) % the years ended December 31, 2016 and 2015. 87,183 25,216 (11,291) (26,958) 74,150 337% (43)% (129)% 106% (152)% For the year ended December 31, 2017, we recorded a profit before income tax of US$25.3 million, compared to a loss of US$48.8 million for the year ended December 31, 2016, primarily due to profits recorded in our Colombian operations. Income tax (expense) Colombia Chile Brazil Other Total Year ended December 31 Change from prior year (in thousands of US$, 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) % 279% (60)% (101)% 77% 266% Income tax expense increased 266%, from US$11.8 million for the year ended December 31, 2016 to US$43.1 million for the year ended December 31, 2017, as a result of higher profits in Colombia. 116 GeoPark 20-F For the year ended December 31 (in thousands of US$, except for percentages) % Change (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 from foreign operations and the attendant royalty regimes. Oil production figures 2016 2015 prior year 145,193 47,477 162,629 47,061 (11)% 192,670 209,690 (8)% delivery. presented on page F-76 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. 1% Gas production presented on page F-77 is gas measured at the point of Revenue Net oil sales Net gas sales Net revenue The following table summarizes certain financial information and operating data. Commodity risk management contracts (2,554) Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful efforts (67,235) (10,282) (34,170) (4,222) (75,774) (31,366) — (86,742) (13,831) (37,471) (5,211) (105,557) (30,084) Impairment loss for non-financial assets 5,664 (149,574) Other operating expense Operating loss Financial costs Foreign exchange gain (loss) Loss before income tax Income tax (expense) benefit Loss for the year Non-controlling interest Loss for the year attributable (1,344) (28,613) (34,101) 13,872 (13,711) (232,491) (35,655) (33,474) (48,842) (301,620) (11,804) 17,054 (60,646) (11,554) (284,566) (50,535) 100% (22)% (26)% (9)% (19)% (28)% 4% (104)% (90)% (88)% (4)% (141)% (84)% (169)% (79)% (77)% to owners of the Company (49,092) (234,031) (79)% Net production volumes Oil (mbbl) (3) Gas (mcf ) (2) 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$) Operating cost Royalties and other Production costs(1) Geological and geophysical expenses Administrative expenses Selling expenses 6,189 11,911 8,174 22,394 5,518 11,493 7,434 20,367 25.6 4.5 7.3 1.5 8.8 1.3 4.5 0.6 32.1 4.6 10.5 1.9 12.4 2.0 5.4 0.7 12% 4% 10% 10% (20)% (2)% (30)% (21)% (29)% (35)% (17)% (14)% GeoPark 117 Net revenue Depreciation Impairment and write-off Chile Colombia 36,723 (31,355) (19,389) 126,228 (31,148) (1,730) Brazil 29,719 (12,974) (4,583) Other — (297) — 2016 Total 192,670 (75,774) (25,702) Year ended December 31 (in thousands of US$) 2015 Chile Colombia 44,808 (39,227) (130,266) 131,897 (52,434) (49,392) Brazil 32,388 (13,568) — Other 597 (328) Total 209,690 (105,557) — (179,658) Revenue For the year ended December 31, 2016, crude oil sales were our principal December 31, 2016 due to higher production. source of revenue, with 75% and 25% of our total revenue from crude oil and gas sales, respectively. The following chart shows the change in oil and The decrease in 2016 net revenue of US$17.0 million is mainly explained by: natural gas sales from the year ended December 31, 2015 to the year ended • a decrease of US$5.7 million in oil sales in Colombia December 31, 2016. Consolidated Sale of crude oil Sale of gas Total By country Colombia Chile Brazil Other Total • a decrease of US$8.1 million in sales in Chile, including US$10.4 million in oil sales partially offset by an increase of US$2.3 million of gas sales. For the year ended December 31 • a decrease of US$2.7 million in sales in Brazil, related to our Manati (in thousands of US$) operations and including US$0.3 million of oil sales and US$2.4 million of gas sales, all of which was due principally to lower oil and gas prices, as 2016 2015 further described below. 145,193 47,477 162,629 Revenue attributable to our operations in Colombia for the year ended 47,061 December 31, 2016 was US$126.2 million, compared to US$131.9 million 192,670 209,690 for the year ended December 31, 2015, representing 66% and 63% of our total consolidated sales. The decrease is related to a decrease in the average realized prices per barrel of crude oil from US$28.8 per barrel to US$24.4 per Year ended December 31 barrel, primarily due to lower reference international prices. This was partially (in thousands of US$, except for percentages) offset by increased sales of crude oil, from 4.6 mmbbl for the year ended % Change December 31, 2015 to 5.4 mmbbl for the year ended December 31, 2016, an from prior increase of 17%. This increase resulted mainly from the development and 2016 2015 year appraisal of the Jacana and Tigana fields in the Llanos 34 Block. 126,228 131,897 36,723 29,719 — 44,808 32,388 597 (5,669) (8,085) (2,669) (597) (4)% Revenue attributable to our operations in Chile for the year ended December (18)% 31, 2016 was US$36.7 million, a 18% decrease from US$44.8 million for the (8)% year ended December 31, 2015, principally due to (1) decreased sales of (100)% crude oil of 0.5 mmbbl for the year ended December 31, 2016 compared to 192,670 209,690 (17,020) (8)% 0.7 mmbbl for the year ended December 31, 2015 (a decrease of 29%) due to the decline in oil base production, (2) decreased average realized prices per Revenue decreased 8%, from US$209.7 million for the year ended December barrel of crude oil from US$42.2 per barrel for the year December 31, 2015 31, 2015 to US$192.7 million for the year ended December 31, 2016, primarily to US$37.0 per barrel for the year ended December 31, 2016 (a decrease of as a result of lower prices. Sales of crude oil increased to 5.9 mmbbl in the US$5.2 per barrel or a total of 12%). The decrease in the average realized price year ended December 31, 2016 compared to 5.3 mmbbl in the year ended per barrel was attributable to lower international reference prices. This was December 31, 2015, and resulted in net revenue of US$145.2 million for the partially offset by an increase in gas sales by US$2.3 million, due to increased year ended December 31, 2016 compared to US$162.6 for the year ended gas production levels as compared to the previous year. The contribution December 31, 2015. In addition, sales of gas increased from US$47.1 million to our revenue during such years from our operations in Chile was 19% and for the year ended December 31, 2015 to US$47.5 million for the year ended 21%, respectively. 118 GeoPark 20-F Revenue attributable to our operations in Brazil for the year ended December 31, 2016 was US$29.7 million, a 8% decrease from US$32.4 million for the year ended December 31, 2015, principally due to decreased sales of gas of 5.8 mmcf for the year ended December 31, 2016 compared to 6.7 mmcf for the year ended December 31, 2015 (a decrease of 13%) due to lower industrial demand. The contribution to our revenue during such years from our operations in Brazil was 15%. Production and operating costs The following table summarizes our production and operating costs for the years ended December 31, 2016 and 2015. For the year ended December 31 (in thousands of US$, except for percentages) % Change from prior 2016 2015 year Consolidated (including Colombia, Chile, Argentina, Peru and Brazil) Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (11,497) (10,859) (2,281) (13,160) (8,283) (3,868) (13,155) (18,562) (4,511) (19,974) (8,591) (3,517) (17,287) (18,432) (13)% (41)% (49)% (34)% (4)% 10% (6)% (67,235) (86,742) (22)% Year ended December 31 (in thousands of US$) 2016 2015 Chile Brazil Colombia Chile Brazil Colombia By country Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (1,495) (5,866) (1,170) (6,122) (1,405) (42) (6,069) (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) (1,973) (7,680) (2,441) (2,998) — — (10,628) (1,651) (1,851) (101) (4,030) — — (36,607) (28,704) (8,150) (9,322) (2,068) (7,611) (6,726) (3,404) (3,407) (8,056) (11,253) (48,534) GeoPark 119 Consolidated production and operating costs decreased 22%, from US$86.7 Administrative costs million for the year ended December 31, 2015 to US$67.2 million for the year ended December 31, 2016, primarily due to cost reduction efforts and efficiencies, partially offset by increased volume sold. Production and operating costs in Colombia decreased 25%, to US$36.6 million for the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily due to cost reduction efforts. In addition, operating costs per boe in Colombia decreased to US$5 per boe for the year Colombia ended December 31, 2016 from US$9 per boe for the year ended December 31, 2015. Production and operating costs in Chile decreased by 23%, due to cost reduction initiatives and operating costs per boe decreased to US$16 per Chile Brazil Other Total For the year ended December 31 (in thousands of US$, except for percentages) 2016 (14,715) (7,153) (3,085) (9,217) 2015 (10,579) (10,978) (2,936) (12,978) (34,170) (37,471) (4,136) 3,825 (149) 3,761 3,301 % Change from prior year 39% (35)% 5% (29)% (9)% boe from US$21 per boe in 2015. In the year ended December 31, 2016, the Administrative costs decreased 9%, from US$37.5 million for the year ended revenue mix for Chile was 51.1% oil and 48.9% gas, whereas for the same December 31, 2015 to US$34.2 million for the year ended December 31, 2016, period in 2015 it was 65.1% oil and 34.9% gas. primarily as a result of continuing financial discipline. Production and operating costs in Brazil increased by 5%, to US$8.4 million for Selling expenses the year ended December 31, 2016, as compared to the year ended December 31, 2015, primarily due to decrease in production. Operating costs per boe increased to US$6 for the year ended December 31, 2016 from US$4 per boe for the year ended December 31, 2015. Geological and geophysical expenses For the year ended December 31 (in thousands of US$, except for percentages) Colombia Chile Brazil % Change Other from prior Total For the year ended December 31 (in thousands of US$, except for percentages) 2016 (2,830) (994) (20) (378) 2015 (3,658) (1,085) — (468) (4,222) (5,211) % Change from prior year (23)% (8)% 100% (19)% (19)% 828 91 (20) 90 989 Colombia Chile Brazil Other Total 2016 (4,296) (1,671) (1,053) (3,262) 2015 (2,798) (4,749) (1,103) (5,181) (10,282) (13,831) (1,498) 3,078 50 1,919 3,549 year 54% Selling expenses decreased 19%, from US$5.2 million for year ended December (65)% 31, 2015 to US$4.2 million for the year ended December 31, 2016, primarily due (5)% to a change in the commercialization mix increasing sales at wellhead in our (37)% Colombian operations. In our Chilean operations, selling expenses were 8% (26)% lower compared to prior year, primarily as a result of lower oil production levels. Geological and geophysical expenses decreased 26%, from US$13.8 million for the year ended December 31, 2015 to US$10.3 million for the year ended December 31, 2016, primarily as the result of higher allocation to capitalized projects and lower staff costs. Operating (loss) profit Colombia Chile Brazil Other Total For the year ended December 31 (in thousands of US$, except for percentages) 2016 31,464 2015 (37,227) (44,969) (180,264) (644) 6,639 (14,464) (21,639) 68,691 135,295 (7,283) 7,175 (28,613) (232,491) 203,878 % Change from prior year (185)% (75)% (110)% (33)% (88)% 120 GeoPark 20-F We recorded an operating loss of US$28.6 million for the year ended December Income tax (expense) benefit 31, 2016, an 88% improvement from the operating loss of US$232.5 million for the year ended December 31, 2015, primarily due to the recognition in 2015 of non-cash impairments of non-financial assets amounting to US$149.6 million (US$104.5 million recorded in Chile and US$45.1 million in Colombia). In 2016, we recorded a gain on non-cash impairments reversal of non-financial assets amounting to US$5.7 million in Colombia, resulting from an improved oil price environment and improvements in cost structure. Financial costs Financial costs decreased 4% to US$34.1 million for the year ended December Colombia Chile Brazil Other 31, 2016 as compared to US$35.7 million for the year ended December 31, 2015, Total mainly due to the impact of lower bank charges and higher interest gains. For the year ended December 31 (in thousands of US$, except for percentages) 2016 (11,969) 2,155 (2,764) 774 (11,804) 2015 (620) 16,893 8,357 (7,576) 17,054 (11,349) (14,738) (11,121) 8,350 (28,858) % Change from prior year 1,830% (87)% (133)% (110)% (169)% Foreign exchange gain (loss) Income tax expense decreased 169%, from US$17.1 million for the year ended December 31, 2015 to a loss of US$11.8 million for the year ended December Foreign exchange variation was 141% to a gain of US$13.9 million for the year 31, 2016, as a result of increased results of operations, mainly related to ended December 31, 2016 as compared to US$33.5 million loss for the year Colombia and Brazil. ended December 31, 2015, mainly because of the appreciation of the real over US$ denominated net debt incurred at the local subsidiary level, where the (Loss) Profit for the year functional currency is the real. (Loss) Profit before income tax For the year ended December 31 (in thousands of US$, except for percentages) Colombia % Change Chile from prior Brazil Other Total year (167)% (70)% 2016 25,845 2015 (38,339) (58,017) (193,683) 8,762 (25,432) (37,980) (31,618) 64,184 135,666 46,742 6,186 Colombia Chile Brazil Other Total For the year ended December 31 (in thousands of US$, except for percentages) 2016 13,876 2015 (38,959) (55,862) (176,789) 5,998 (24,658) (29,623) (39,195) 52,835 120,927 35,621 14,537 (60,646) (284,566) 223,920 % Change from prior year (136)% (68)% (120)% (37)% (79)% (123)% For the year ended December 31, 2016, we recorded a loss of US$60.6 million (20)% as a result of the reasons described above. (48,842) (301,620) 252,778 (84)% (Loss) Profit for the year attributable to owners of the Company For the year ended December 31, 2016, we recorded a loss before income tax of US$48.8 million, compared to a loss of US$301.6 million for the year Loss for the year attributable to owners of the Company decreased by 79% ended December 31, 2015, primarily due to decreased losses from our Chilean to US$49.1 million, for the reasons described above. Loss attributable to non- and Other operations and profits recorded in our Colombian and Brazilian controlling interest decreased by 77% to US$11.6 million for the year ended operations. December 31, 2016 as compared to the prior year. B. Liquidity and capital resources Overview Our financial condition and liquidity is and will continue to be influenced by a variety of factors, including: • changes in oil and natural gas prices and our ability to generate cash flows from our operations; • our capital expenditure requirements; • the level of our outstanding indebtedness and the interest we are obligated GeoPark 121 to pay on this indebtedness; and March 21 2018, we made a semi-annual interest payment on the Notes due • changes in exchange rates which will impact our generation of cash flows 2024 in the amount of US$13.8 million. from operations when measured in US$, and the real. We repurchased US$284.0 million aggregate principal amount of the Our principal sources of liquidity have historically been contributed outstanding Notes due 2020 in September 2017, and redeemed the remaining shareholder equity, debt financings and cash generated by our operations. US$16.0 million aggregate principal amount outstanding in October 2017, Since 2005 to 2017, we have raised approximately US$200 million in equity using funds received in connection with the settlement of the Notes due 2024. offerings at the holding company level and nearly US$1 billion through debt The total consideration paid for the validly tendered and accepted Notes due arrangements with multilateral agencies such as the IFC, gas prepayment 2020 was US$1,041.25 per US$1,000 principal amount of 2020 Notes, which facilities with Methanex, international bond issuances and bank financings, included an early tender payment of US$30 per US$1,000 principal amount described further below, which have been used to fund our capital of 2020 Notes for holders who tendered their notes by September 19, 2017, expenditures program and acquisitions and to increase our liquidity. plus accrued and unpaid interest to, but not including, September 21, 2017. We have also raised US$182.1 million to date through our strategic partnership We redeemed the remaining US$16.0 million aggregate principal amount with LGI following the sale of minority interests in our Colombian and Chilean outstanding of the Notes due 2020 at a price equal to 103.75% of the principal operations. amount thereof, plus accrued and unpaid interest (including additional In February 2014, we commenced trading on the NYSE and raised US$98 amounts, if any) from August 11, 2017 to, but excluding October 21, 2017. million (before underwriting commissions and expenses), including the over- allotment option granted to and exercised by the underwriters, through the We believe that our current operations and 2018 capital expenditures program issuance of 13,999,700 common shares. can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including In February 2013, we issued US$300.0 million aggregate principal amount of delivery restrictions or a protracted downturn in oil and gas prices, we would 7.50% senior secured notes due 2020 (the “Notes due 2020”). examine measures such as further capital expenditure program reductions, pre-sale agreements, disposition of assets, or issuance of equity, among In December 2015, we entered into an offtake and prepayment agreement others. with Trafigura under which we will sell a portion of our Colombian crude oil production to Trafigura in exchange for advance payments of up to US$100 Capital expenditures million, subject to applicable volumes corresponding to the terms of the In the past, we have funded our capital expenditures with proceeds from agreement. Funds committed by Trafigura were available to us upon request equity offerings, credit facilities, debt issuances and pre-sale agreements, until September 2017 to be repaid by us on a monthly basis through future as well as through cash generated from our operations. We expect to incur oil deliveries until December 2018. As of October 2017, we are no longer substantial expenses and capital expenditures as we develop our oil and obligated to pay a commitment fee for any unused commitment under the natural gas prospects and acquire additional assets. See “Item 4. Information Trafigura Agreement. on the Company –B. Business Overview—2018 Strategy and Outlook.” In September 2017, we issued US$425.0 million aggregate principal amount In the year ended December 31, 2017, we made total capital expenditures of of senior secured notes due 2024. The Notes due 2024 mature on September US$105.6 million (US$80.0 million, US$10.2 million, US$8.2 million, US$3.6 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per million and US$3.6 million in Colombia, Chile, Argentina, Peru and Brazil, year. Interest on the Notes due 2024 is payable semi-annually in arrears respectively). on March 21 and September 21 of each year. The Indenture governing our Notes due 2024 contains incurrence-based limitations on the amount of In the year ended December 31, 2016, we made total capital expenditures of indebtedness we can incur. This situation may limit our capacity to incur US$39.3 million (US$26.2 million, US$7.8 million, US$1.7 million and US$3.6 additional indebtedness, other than permitted debt, as specified in the million in Colombia, Chile, Argentina and Brazil, respectively). indenture governing the Notes. The net proceeds from the Notes were used by us (i) to make a capital contribution to our wholly-owned subsidiary, Cash flows GeoPark Latin America Limited Agencia en Chile, providing it with sufficient The following table sets forth our cash flows for the periods indicated: funds to fully repay the 7.50% senior secured notes due 2020 and to pay any related fees and expenses, including a call premium, and (ii) for general corporate purposes, including capital expenditures, such as the acquisition of Aguada Baguales, El Porvenir and Puesto Touquet blocks in Neuquen basin in Argentina, and to repay existing indebtedness, including the Itaú loan. On 122 GeoPark 20-F Year ended December 31, Indebtedness (in thousands of US$) As of December 31, 2017 and 2016, we had total outstanding indebtedness 2015 of US$426.2 million and US$358.7 million, respectively, as set forth in the Cash flows provided by (used in) Operating activities Investing activities Financing activities Net increase (decrease) 2017 142,158 (105,604) 23,968 2016 82,884 (39,306) (51,136) 25,895 table below. (48,842) (18,022) BCI Loans Bond GeoPark Latin America Agencia in cash and cash equivalents 60,522 (7,558) (40,969) en Chile (Notes due 2020) Bond GeoPark Limited (Notes due 2024) Cash flows provided by operating activities Banco de Chile For the year ended December 31, 2017, cash provided by operating activities Rio das Contas Credit Facility was US$142.2 million, a 72% increase from US$82.9 million for the year Total ended December 31, 2016, resulting from the increase in oil prices in 2017 as compared to 2016, net of a US$15.6 million advance payment paid in As of December 31, (in thousands of US$) 2016 80 — 426,124 — — 2017 141 304,059 — 4,709 49,763 426,204 358,672 December 2017 to Pluspetrol, as a security deposit related to the recently Our material outstanding indebtedness as of December 31, 2017 is announced acquisition of Aguada Baguales, El Porvenir and Puesto Touquet described below. blocks in Neuquen basin in Argentina. Notes due 2024 For the year ended December 31, 2016, cash provided by operating activities was US$82.9 million, a 220% increase from US$25.9 million for the year ended General December 31, 2015, resulting from cost reduction efforts, lower income tax On September 21, 2017, we issued US$425.0 million aggregate principal paid and increased funds from working capital, including customer advance amount of senior secured notes due 2024. The Notes due 2024 mature on payments from Trafigura. September 21, 2024 and bear interest at a fixed rate of 6.50% and a yield of 6.50% per year. Interest on the Notes due 2024 is payable semi-annually in Cash flows used in investing activities arrears on March 21 and September 21 of each year. For the year ended December 31, 2017, cash used in investing activities was US$105.6 million, a 169% increase from US$39.3 million for the year ended Ranking December 31, 2016. This increase was related to higher capital expenditures The Notes due 2024 constitute senior unsubordinated obligations of GeoPark in Colombia, Chile, Argentina and Peru in 2017 as compared to 2016. Limited, secured by a first lien on the Collateral (as described below). The Notes due 2024 rank equally in right of payment with all existing and future senior For the year ended December 31, 2016, cash used in investing activities was obligations of GeoPark Limited (except those obligations preferred by operation US$39.3 million, a 20% decrease from US$48.8 million for the year ended of Bermuda law, including without limitation labor and tax claims); rank senior December 31, 2015. This decrease was related to lower capital expenditures to all unsecured debt of GeoPark Limited to the extent of the value of the in Colombia, Chile and Brazil in 2016 as compared to 2015, despite having Collateral; rank senior in right of payment to all existing and future subordinated similar activity levels. indebtedness of GeoPark Limited; and rank effectively junior to any future secured obligations of GeoPark Limited and its subsidiaries with a security Cash flows from financing activities interest on assets not constituting Collateral, in each case, to the extent of the Cash from financing activities was US$24.0 million for the year ended value of the collateral securing such obligations. December 31, 2017, compared to US$51.1 million used in financing activities for the year ended December 31, 2016. This change was Collateral principally related to net proceeds from the issuance of 2024 Notes of The notes are secured by a first-priority perfected security interest in certain US$418.3 million offset by principal paid of US$355.0 million related to the collateral (the “Collateral”), which consists of 80% of the equity interests of payment of 2020 Notes and the prepayment of the Itaú loan. each of GeoPark Chile and GeoPark Colombia. Cash used in financing activities was US$51.1 million for the year ended Optional redemption December 31, 2016, compared to US$18.0 million for the year ended We may, at our option, redeem all or part of the Notes due 2024, at the December 31, 2015. This change was principally the result of principal redemption prices, expressed as percentages of principal amount, set forth payments related to Itaú loan and dividends distribution to non-controlling below, plus accrued and unpaid interest thereon (including additional interest. amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on September 21 of the years indicated below: GeoPark 123 Year 2021 2022 2023 and after Change of control Percentage Events of default under the indenture governing the Notes due 2024 include: 103.250% the nonpayment of principal when due; default in the payment of interest, 101.625% which continues for a period of 30 days; failure to make an offer to purchase 100.000% and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indenture governing the Notes due 2024; the notes, or the security documents in relation thereto Upon the occurrence of certain events constituting a change of control, we that continues for a period of 60 consecutive days after written notice; cross are required to make an offer to repurchase all outstanding Notes due 2024, payment default relating to debt with a principal amount of US$30.0 million at a purchase price equal to 101% of the principal amount thereof plus any or more, and cross-acceleration default following a judgment for US$30.0 accrued and unpaid interest (including any additional amounts payable in million or more; bankruptcy and insolvency events; invalidity or denial or respect thereof ) thereon to the date of purchase. If holders of not less than disaffirmation of a guarantee of the notes; and failure to maintain a perfected 90% in aggregate principal amount of the outstanding Notes due 2024 validly security interest in any collateral having a fair market value in excess of tender and do not withdraw such notes and we repurchase all such notes, US$15.0 million, among others. The occurrence of an event of default would we may redeem the Notes due 2024 that remain outstanding following such permit or require the principal of and accrued interest on the Notes due 2024 purchase at a price in cash equal to 101% of the principal amount thereof plus to become or to be declared due and payable. accrued and unpaid interest to but excluding the date of such redemption. Banco de Chile Covenants During December 2015, we entered into a loan agreement with Banco de The Notes due 2024 contain customary covenants, which include, among Chile for US$7.0 million to finance the start-up of the new Ache gas field in others, limitations on the incurrence of debt and disqualified or preferred stock, the Fell Block. The interest rate applicable to this loan is LIBOR plus 2.35% per restricted payments (including restrictions on our ability to pay dividends), year. The interest and the principal have been paid on a monthly basis with a incurrence of liens, guarantees of additional indebtedness, the ability of certain 6-month grace period and final maturity on December 2017. subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another BCI Loan company. During February 2016, we executed a loan agreement with Banco de Crédito e Inversiones (BCI) to finance the acquisition of vehicles for our Chilean operations. In the event the Notes due 2024 receive investment-grade ratings from at least The interest rate applicable to this loan is 4.14% per annum. The interest and the two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, principal will be paid on monthly basis, with final maturity on February 2019. and no default has occurred or is continuing under the indenture governing the Notes due 2020, certain of these restrictions, including, among others, the LGI Line of Credit limitations on incurrence of debt and disqualified or preferred stock, restricted As of December 31, 2017, the aggregate outstanding amount under the LGI Line payments (including restrictions on our ability to pay dividends), the ability of of Credit was US$31.2 million. This corresponds to advanced cash call payments certain subsidiaries to pay dividends, asset sales and certain transactions with granted by LGI to GeoPark Chile for financing Chilean operations in our Tierra affiliates will no longer be applicable. del Fuego blocks. The maturity of this balances is July 2020 and the applicable The indenture governing our Notes due 2024 includes incurrence test covenants that provide, among other things, that, the net debt to EBITDA ratio See “Item 4. Information on the Company—B. Business Overview—Significant interest rate is 8% per year. should not exceed (i) 3.50 until September 21, 2019, (ii) 3.25 from September Agreements—Agreements with LGI.” 21, 2019 to September 21, 2021, and (iii) 3.00 thereafter until maturity, and the EBITDA to interest ratio should exceed (i) 2.00 until September 21, 2019, (ii) 2.25 Rio das Contas Credit Facility from September 21, 2019 to September 21, 2021 and (iii) 2.50 thereafter until We financed our Rio das Contas acquisition in part through our Brazilian maturity. Failure to comply with the incurrence test covenants does not trigger subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas an event of default. However, this situation may limit our capacity to incur Credit Facility”) with Itaú BBA International plc, which was secured by the additional indebtedness, as specified in the indenture governing the Notes due benefits GeoPark receives under the Purchase and Sale Agreement for Natural 2024, other than certain categories of permitted debt. We must test incurrence Gas with Petrobras. The loan was fully repaid in September 2017. covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted Other Agreements payments and others (in each case with certain specific exceptions). In December 2015, we entered into an offtake and prepayment agreement with Events of default 124 GeoPark 20-F Trafigura under which we sell and deliver a portion of our Colombian crude oil production. Pricing will be determined by future spot market prices, net of transportation costs. The agreement also provides us with prepayment of up to US$100 million from Trafigura. Funds committed will be made available to us upon request and will be repaid by us on a monthly basis through future oil deliveries over the period of the contract, which is 2.5 years, including a 6-month grace period. According to the terms of the prepayment agreement, we are required to pay interest of LIBOR plus 5% per year on outstanding amounts. In addition, under the prepayment agreement, we are required to maintain certain coverage ratios linking: (i) future payments to the value of estimated future oil deliveries (net of transportation discounts) during the term of the offtake agreement and (ii) collections to payments within specified periods, with the possibility of delivering additional volumes to meet such ratios in the upcoming 3-month period. As of March 31, 2018, outstanding amounts related to the prepayment agreement amount to US$7.5 million. C. Research and development, patents and licenses, etc. See “Item 4. Information on the Company——B. Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to Properties.” D. Trend information For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information on the Company –B. Business Overview—2018 Strategy and Outlook.” E. Off-balance sheet arrangements We did not have any off-balance sheet arrangements as of December 31, 2017 or as of December 31, 2016. F. Tabular disclosure of contractual obligations In accordance with the terms of our concessions, we are required to pay royalties in connection with our crude oil and natural gas production. See Note 32(a) to our Consolidated Financial Statements. GeoPark 125 Directors, senior management and employees The table below sets forth our committed cash payment obligations as of December 31, 2017. Debt obligations(1) Operating lease obligations(2) Pending investment commitments(3) Asset retirement obligations Total contractual obligations Total 618,455 40,750 53,791 38,075 751,071 Less than one year (in thousands of US$) Three to five years More than five years One to three years 27,693 32,180 31,338 — 91,211 55,262 5,777 22,453 — 83,492 55,250 2,793 — — 58,043 480,250 — — 38,075 518,325 (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$27.7 million; one to three years: US$55.3 million and three to five years: US$55.3 million. At December 31, 2017, 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 Isla Norte, Campanario and Flamenco Blocks in Chile, rounds 11, 12 and 13 concessions in Brazil, three blocks in Argentina and the Llanos 32, VIM-3, and Llanos 34 Blocks in Colombia. See “Item 4. Information on the Company—B. Business Overview—Our operations” and Note 32(b) 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 seven 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 2018. The current members of the board of directors were appointed at our annual general meeting held on July 19, 2017. Two previously elected members, Mr. Peter Ryalls and Mr. Michael D. Dingman, passed away following the 2017 annual general meeting, generating two vacancies on our board of directors. The table below sets forth certain information concerning our current board of directors. All ages are as of March 31, 2018. 126 GeoPark 20-F Name Gerald E. O’Shaughnessy James F. Park Carlos A. Gulisano (3) Juan Cristóbal Pavez (1)(2) Robert Bedingfield (1)(2) Pedro E. Aylwin Chiorrini Jamie B. Coulter (2) Position Chairman and Director Chief Executive Officer, Deputy Chairman and Director Director Director Director Director, Director of Legal and Governance, Corporate Secretary Director Age At the Company since 69 62 67 47 69 58 77 2002 2002 2010 2008 2015 2003 2017 (1) Member of the Audit Committee. (2) Independent director under SEC Audit Committee rules. (3) Carlos Gulisano joined the Company in 2002 as an advisor. 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 oil and gas exploration Biographical information of the current members of our Board of Directors is company, in Guatemala. He remained a member of the board of directors of set forth below. Unless otherwise indicated, the current business addresses for Basic Resources International Limited until the company was sold in 1997. Mr. our directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile. Park is also a member of the board of directors of Energy Holdings and has Gerald E. O’Shaughnessy has been our Chairman and a member of our Yemen and China. Mr. Park is a member of the AAPG and SPE and has lived in also been involved in oil and gas projects in California, Louisiana, Argentina, board of directors since he co-founded the company in 2002. Following his 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 of portfolio analyst at Moneda Asset Management. In 1998, he joined Santana, our board of directors since co-founding the Company in 2002. He has over an investment company, as Chief Executive Officer, where he focused mainly 40 years of experience in all phases of the upstream oil and gas business, with on investments in capital markets and real estate. While at Santana, he was a strong background in the acquisition, implementation and management appointed Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s of international projects and teams in North America, South America, Asia, main assets. In 1999, Mr. Pavez co-founded Eventures, an internet company. Europe and the Middle East. He received a bachelor of science degree in Since 2001, he has served as Chief Executive Officer at Centinela, a company GeoPark 127 with a diversified global portfolio of investments. Mr. Pavez is also a board Counsel at BHP Billiton, Base Metals, where he was in charge of legal and member of Grupo Security, Vida Security and Hidroelétrica Totoral. Over the corporate governance matters on BHP Billiton’s projects, operations and last few years he has been a board member of several companies, including natural resource assets in South America, North America, Asia, Africa and Quintec, Enaex, CTI and Frimetal. Australia. Robert Bedingfield has been a member of our board of directors since March Jamie B. Coulter is a well-respected businessman, who has spearheaded 2015. He holds a degree in Accounting from the University of Maryland and the growth of a variety of businesses in diverse sectors. He holds a business is a Certified Public Accountant. Until his retirement in June 2013, he was one degree from Wichita State University and is a graduate of the Stanford of Ernst & Young’s most senior Global Lead Partners with more than 40 years University Executive Program. Mr. Coulter currently serves as Managing of experience, including 32 years as a partner in Ernst & Young’s accounting Member of Coulter Enterprises LLC., a private investment firm. Mr. Coulter and auditing practices, as well as serving on Ernst & Young’s Senior Governing has been an investor in GeoPark since 2006. Mr. Coulter has more than 46 Board. He has extensive experience serving Fortune 500 companies; including years of experience in the food retail and restaurant business, serving as Chief acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, Executive Officer of Lone Star Steakhouse & Saloon and having developed AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US and operated Pizza Hut and Kentucky Fried Chicken restaurants. Mr. Coulter Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times is a former Restaurants & Institutions CEO of the year. Mr. Coulter has an Executive Committee Member, and the Audit Committee Chair of the operating and investment experience in the oil and gas business, including University of Maryland at College Park Board of Trustees. Mr. Bedingfield the founding of Sunburst Exploration, a US upstream oil and gas company served on the National Executive Board (1995 to 2003) and National Advisory that he built throughout the 1980s and sold in 1994. Mr. Coulter also has been Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield an active participant as an investor in North American shale plays during the has also served as Board Member and Chairman of the Audit Committee of last ten years. Mr. Coulter currently serves as a Director of the Federal Law NYSE-listed Science Applications International Corp (SAIC). Enforcement Foundation and is a member of the Board of Trustees for HCA Pedro E. Aylwin Chiorrini has served as a member of our board of directors directors, including as a Director of Jimmy Johns LLC, Chairman of the Board since July 2013 and as our Director of Legal and Governance since April 2011. of the International Pizza Hut Franchise Holders’ Association, a member of the From 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance Board of Advisors of The Wichita State University Center for Entrepreneurship and legal matters. Mr. Aylwin holds a degree in law from the Universidad de and a member of the Board of Trustees for the University of Kansas School of Wesley Medical Center, and has previously served on a number of boards of Chile and an LLM from the University of Notre Dame. Mr. Aylwin has extensive Business, among others. 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 Executive officers he represented mining, chemical and oil and gas companies in numerous Our executive officers are responsible for the management and representation transactions. From 2006 until 2011, he served as Lead Manager and General of our company. The table below sets forth certain information concerning our executive officers. All ages are as of March 31, 2018. 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 Alberto Matamoros Barbara Bruce Marcela Vaca Carlos Murut Salvador Minniti Horacio Fontana Agustina Wisky Guillermo Portnoi Stacy Steimel 128 GeoPark 20-F Chief Operating Officer Director for Argentina, Brazil and Chile Director for Peru Director for Colombia Director of Development Director of Exploration Director of Drilling Director of Business Management Director of New Business Director of Shareholder Value Age At the Company since 62 40 58 48 46 61 49 61 63 60 41 42 58 2002 2010 2003 2006 2014 2017 2012 2006 2007 2008 2002 2006 2017 Biographical information of the members of our executive officers is set in IAE, from the Business School of Universidad Austral of Buenos Aires, forth below. Unless otherwise indicated, the current business addresses Argentina. for our executive officers is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile. Barbara Bruce has been our Director for Peru since June 2017. Ms. Bruce holds a degree in Geology from the Universidad Nacional de Ingeniería, Andrés Ocampo has served as our Chief Financial Officer since November Lima, Peru, a Master’s degree in Reservoirs from Colorado School of Mines, 2013. He previously served as our Director of Growth and Capital (from USA and an MBA from Universidad Adolfo Ibañez, USA/Chile. Before joining January 2011 through October 2013), and has been with our company since GeoPark, she previously worked with Occidental Petroleum in different July 2010. Mr. Ocampo graduated with a degree in Economics from the international operations, including in the Caño Limon field in Colombia Universidad Católica Argentina. He has more than 16 years of experience in and the Dhurnal and Bhangali gas fields in Pakistan. Ms. Bruce later worked business and finance. Before joining our company, Mr. Ocampo worked at as deputy President of an offshore operation by Petrotech Peruana, joined Citigroup and served as Vice President Oil & Gas and Soft Commodities at Hunt Oil and as General Manager of Peru LNG, leading the construction and Crédit Agricole Corporate & Investment Bank. startup of operation of Peru´s first LNG plant and managed the exploration venture of Hunt Oil in Madre de Dios, Peru. Augusto Zubillaga has served as our Chief Operating Officer since May 2015. He previously served in other management positions throughout Marcela Vaca has been our Director for Colombia since August 2012. Ms. the Company including as Operations Director, Argentina Director and Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá, Production Director. He previously served as our Production Director. He is Colombia, a Master’s Degree in commercial law from the same university a petroleum engineer with more than 23 years of experience in production, and an LLM from Georgetown University. She has served in the legal engineering, well completions, corrosion control, reservoir management departments of a number of companies in Colombia, including Empresa and field development. He has a degree in petroleum engineering from Colombiana de Carbon Ltda (which later merged with INGEOMINAS), and the Instituto Tecnológico de Buenos Aires. Prior to joining our company, from 2000 to 2003, she served as Legal and Administrative Manager at GHK Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron Company Colombia. Prior to joining our company in 2012, Ms. Vaca served San Jorge S.A. At Chevron San Jorge S.A., he led multi-disciplinary teams for nine years as General Manager of the Hupecol Group where she was focused on improving production, costs and safety, and was the leader of responsible for supervising all areas of the company as well as managing the Asset Development Team, which was responsible for creating the field relationships with Ecopetrol, ANH, the Colombian Ministry of Mines and development plan and estimating and auditing the oil and gas reserves of Energy, the Colombian Ministry of Environment and other governmental the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron San agencies. At the Hupecol Group, Ms. Vaca was also involved in the Jorge S.A. team that was responsible for identifying business opportunities structuring of the Hupecol Group’s asset development and sales strategy. and working with the head office on the establishment of best business practices. He has authored several industry papers, including papers Carlos Murut has been our Director of Development since January 2012. He on electrical submersible pump optimization, corrosion control, water previously served as our Development Manager. Mr. Murut holds a master’s handling and intelligent production systems. degree in petroleum geology from the University of Buenos Aires where he Alberto Matamoros has been our Director for Argentina, Brazil, Chile and in field exploitation. He also completed a Business Management Peru since March 2016 and Director for Chile since January 2015. He is an Development Program at Austral University. Mr. Murut has over 40 years of industrial engineer and has an MBA, with more than 20 years of experience experience working for international and major oil companies, including in the Oil & Gas industry. He started his career in the Argentinian oil YPF S.A., Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San also undertook postgraduate studies in reservoir engineering, specializing company ASTRA, as a Production Engineer of La Ventana-Vizcacheras Block Jorge S.A. in the province of Mendoza (1997-2000). He then joined Chevron, where he worked as a Production Engineer in El Trapial Block in the province of Salvador Minniti has been our Director of Exploration since January 2012. Neuquén for three years. Later, he became a Field Engineering Manager, He previously served as our Exploration Manager. He holds a bachelor also for three years, in Buenos Aires, and then moved to Kern County, degree in geology from National University of La Plata and has a graduate California, to lead the production team. His experience in Chevron enabled degree from the Argentine Oil and Gas Institute in oil geology. Mr. Minniti him to manage different technical and administrative teams, designing has over 35 years of experience in oil exploration and has worked with YPF and executing working plans focused in the optimization of resources. In S.A., Petrolera Argentina San Jorge S.A. and Chevron Argentina. 2014, he joined GeoPark to be part of the Corporate Operation team before being selected as the new Director for Chile. Matamoros holds a degree in Horacio Fontana has been our Corporate Drilling Manager since March Industrial Engineering from the Universidad Nacional del Sur and an MBA 2012. He previously served as our Engineer Manager. He holds a degree in GeoPark 129 civil engineering from Rosario National University and is also a graduate It is our current policy that executive directors enter into indefinite term from the Argentine Oil and Gas Institute, National University of Buenos contracts with the Company that may be terminated at any time by either Aires, with a specialty in oilfield exploitation and an extensive background party subject to certain notice requirements. in drilling operations. He has recently taken part in a Management Development Program at IAE Business School of Austral University. Mr. Gerald E. O’Shaughnessy has entered into a service contract with the Fontana has over 31 years of drilling experience in major Argentine Company to act as Chairman at an annual salary of US$400,000. James F. companies such as YPF S.A., Petrolera Argentina San Jorge and Chevron. Park has entered into a service contract with the Company to act as Chief Agustina Wisky has worked with our Company since it was founded in equity awards described below under “Equity Incentive Compensation.” Our November 2002, and has served as our Director of People since 2012 until agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that December 2016 and is currently our Director of Business Management. Mrs. restrict them, for a period of 12 months following termination of employment, Wisky is a public accountant, and also holds a degree in human resources from soliciting senior employees of the Company and, for a period of six from the Universidad Austral—IAE. She has 15 years of experience in the oil months following a termination of employment, from competing with the Executive Officer at an annual salary of US$800,000. They each also received industry. Before joining our company, Mrs. Wisky worked at AES Gener and Company. PricewaterhouseCoopers. Guillermo Portnoi has worked with our Company since June 2006 and has 2013, has entered into a service contract with the Company to act as Director been our Director of Business Management since May 2015 until December of Legal and Governance, and as such has decided to forego his director fees. 2016 and is currently our Director of New Business. Previously, he also He instead received in 2017 a salary of US$0.3 million and bonus of US$0.1 served as our Director of Administration and Finance. Mr. Portnoi is a public million for his services as a member of senior management. accountant and holds an MBA from Universidad Austral—IAE. He has more than 14 years of experience in the oil industry. Before joining our company, The following chart summarizes payments made to our executive directors for Pedro E. Aylwin Chiorrini, who was appointed as an executive director in July Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers, the year ended December 31, 2017: where he counted several major oil companies as his clients. Stacy Steimel joined GeoPark in February 2017 as our Shareholder Value Executive Directors’ Fees Director. Mrs. Steimel has more than 20 years of experience in the financial Gerald E. O’Shaughnessy US$400,000 Cash payment Bonus — sector as Fund Manager and subsequently as regional CEO for PineBridge James F. Park Investments, ex-AIG Investments in Latin America. Before AIG, Mrs. Steimel Pedro E. Aylwin Chiorrini US$800,000 US$800,000 — — held positions in the US Treasury Department and at the InterAmerican 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 March, 16 2017 and reflect awards for previous years’ performance including Texas at Austin and a BA from the College of William and Mary. the discretionary bonus payments made based on our performance in 2016. B. Compensation Executive compensation Non-Executive Director Contracts The current annual fees paid to our non-executive Directors correspond to US$80,000 to be settled in cash and US$100,000 to be settled in stock, paid For the year ended December 31, 2017, we accrued or paid approximately quarterly in equal installments. In the event that a non-executive Director US$4.5 million, in the aggregate, to the members of our board of directors serves as Chairman of any Board Committees, an additional annual fee (including our executive directors) for their services in all capacities. During of US$20,000 applies. A Director who serves as a member of any Board this same period, we accrued or paid approximately US$7.8 million, in the Committees receives an annual fee of US$10,000. Total payment due shall aggregate, to the members of our senior management (excluding our be calculated on an aggregate basis for Directors serving in more than one executive directors) for their services in all capacities. An amount of US$0.9 Committee. The Chairman fee is not added to the member’s fee while serving million corresponds to the accrual or payment for discretionary bonus for the same Committee. Payments of Chairmen and Committee members’ cash payments granted to the Company’s executive directors based on the fees are made quarterly in arrears and settled in cash only. Company’s performance in 2017. Gerald E. O’Shaughnessy, James F. Park and Pedro E. Aylwin Chiorrini are our executive directors. The following chart summarizes payments made to our non-executive directors for the year ended December 31, 2017. Executive Director Contracts 130 GeoPark 20-F Number of underlying common shares Non-Executive Director Juan Cristóbal Pavez (2) Carlos Gulisano (3) Robert Bedingfield (4) Peter Ryalls(5) Michael D. Dingman(5) Jamie B. Coulter Non-Executive Directors’ Fees in US$ 110,000 110,000 102,500 115,000 46,667 50,000 Fees paid in Common Shares (1) 15,408 15,408 15,408 9,388 8,853 6,020 outstanding 976,211(1) 817,600(1) 478,000(1) 720,000(2) 379,500 490,000 1,619,105 (3) Grant date 12/15/2008 12/15/2010 12/15/2011 11/23/2012 12/15/2012 12/31/2014 06/30/2016 Vesting date Expiration date 12/15/2012 12/15/2014 12/15/2015 11/23/2015 12/15/2016 12/31/2017 06/30/2019 12/15/2018 12/15/2020 12/15/2021 11/23/2016 12/15/2022 12/31/2022 06/30/2026 (1) The numbers in this column are equal to 70,485 Common Shares (which amount equals to US$454,058). (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) Mr. Peter Ryalls and Mr. Michael D. Dingman passed away following the 2017 annual general meeting. (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 that runs through 2016 to 2018. If such conditions are not achieved as of the vesting date, only the equivalent of one monthly salary will be issued in Pension and retirement benefits shares. We do not maintain any defined benefit pension plans or any other retirement programs for our employees or directors. Equity Incentive Compensation Our executive directors, senior management and employees who have received option awards or common share awards under the Stock Awards Plan authorize the Company to deposit any common shares they have received under this plan in our Employee Benefit Trust (“EBT”). The EBT is Performance-Based Employee Long-Term Incentive Program held to facilitate holdings and dispositions of those common shares by the participants thereof. Under the terms of the EBT, each participant is entitled to In November 2007, our shareholders voted to authorize the board of directors receive any dividends we may pay which correspond to their common shares to use up to a maximum of 12% of our issued share capital for the purposes held by the trust, according to instructions sent by the Company to the trust of granting equity awards to our employees and other service providers. The administrator. The trust provides that Mr. James F. Park is entitled to vote all shareholders also authorized the board of directors to adopt programs for this the common shares held in the trust. purpose and to determine specific conditions and broadly defined guidelines for such programs. Stock Awards Plan Value Creation Plan On December 10, 2015, the Board of Directors approved a renewal of the VCP for a new period of three years, with new rewards granted on January 1, The purpose of the Stock Awards Plan is to align the interests of our 2016. Under the current VCP, if as of December 31, 2018, our share price has management, employees and key advisors with those of shareholders. Under increased by 12% per year according to the plan conditions, VCP participants the Stock Awards Plan, the board of directors, or its designee, may award (key management) will receive awards with an aggregate value equal to 10% options or stock awards. An option confers the right to acquire a specified of the excess above the market capitalization threshold generated by this number of common shares of the Company at an exercise price equal to the share price (assuming that the share capital of the Company had remained par value of the common shares subject to such an option. A performance at the same level as applicable at the time of establishment of the VCP: share confers a conditional right to acquire a specified number of common 59,535,614 shares). The awards will vest and be paid in common shares 50% shares for zero or nominal consideration, subject to the achievement of on December 31, 2018, and the remaining 50% on December 31, 2019. As in performance conditions and other vesting terms. the previous VCP, the total number of common shares granted pursuant to this plan shall not exceed 5% of the issued share capital of the Company. For On December 17, 2014, we registered 3,435,600 shares with the U.S. SEC for further details see Note 30 to our Consolidated Financial Statements. shares to be issued under the Stock Awards Plan. The following table sets forth the common share awards granted to our executive directors, management Non-Executive Director Plan and employees under the Stock Awards Plan commencing in 2008 through In August 2014, our Board of Directors adopted the Non-Executive Director March 31, 2018. Plan in order to grant shares to non-executive directors as part of their compensation program for serving as directors, which was amended and restated in October 2016. 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 GeoPark 131 committee may award common shares, restricted share units and other share- Audit Committee based awards that may be denominated or payable in common shares or The Audit Committee is composed of three directors. The current members of factors that influence the value of common shares. The maximum number of the Audit Committee are Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield common shares available for issuance under the Non-Executive Director Plan (who currently serves as Chairman of the committee). We have determined is 1,000,000 common shares. that Mr. Juan Cristóbal Pavez and Robert Bedingfield are independent, as such term is defined under SEC rules applicable to foreign private issuers. Currently, Potential dilution resulting from Equity Incentive Compensation Plans there is a vacancy created by the passing of Mr. Peter Ryalls on July 25, 2017. The percentage of total share capital that could be awarded to our directors, management and key employees under the Stock Awards Plan described The Audit Committee’s responsibilities include: (a) approving our financial above would represent approximately 14% of our issued common shares statements; (b) reviewing financial statements and formal announcements as of December 31, 2017. In accordance with existing equity compensation relating to our performance; (c) assessing the independence, objectivity plans as of the date of this annual report, there are approximately 4.6 million and effectiveness of our external auditors; (d) making recommendations for outstanding shares that have been awarded but which have not yet vested, the appointment, re-appointment and removal of our external auditors and representing approximately 7.5% of the total issued share capital as of approving their remuneration and terms of engagement; (e) implementing December 31, 2017. C. Board practices Overview 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 expertise if it considers it necessary; and (g) reviewing our arrangements Our Board of Directors is responsible for establishing our listed company for our employees to raise concerns about possible wrongdoing in financial goals, ensuring that the necessary resources are in place to achieve reporting or other matters and the procedures for handling such allegations, these goals and reviewing our management and financial performance. and ensuring that these arrangements allow proportionate and independent Our board of directors directs and monitors the company in accordance investigation of such matters and appropriate follow-up action. with a framework of controls, which enable risks to be assessed and managed through clear procedures, lines of responsibility and delegated Compensation Committee authority. Our board of directors also has responsibility for establishing The Compensation Committee is composed of three directors. The current our core values and standards of business conduct and for ensuring that members of the compensation committee are Mr. Juan Cristóbal Pavez these, together with our obligations to our shareholders, are understood (who serves as Chairman of the committee) and Mr. Carlos Gulisano. throughout the company. Currently there is one vacancy created by the passing of Mr. Peter Ryalls on Board composition July 25, 2017. 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 19, 2017. 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 2018. 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). 132 GeoPark 20-F The Nomination Committee meets at least twice a year and its responsibilities The following table sets forth a breakdown of our employees by geographic include: (a) reviewing the structure, size and composition of the board of segment for the periods indicated. directors and making recommendations to the board of directors in respect of any required changes; (b) identifying, nominating and submitting for approval by the board of directors candidates to fill vacancies on the board of directors as and when they arise; (c) making recommendations to the board of directors Colombia with respect to the membership of the Audit Committee and Compensation Committee in consultation with the chairman of each committee, and with Chile Brazil respect to the appointment of any director or executive officer or other officer Argentina other than the position of the Chairman and Chief Executive Officer and (d) succession planning for directors and senior executives. Peru Total Year ended December 31, 2017 180 102 12 92 19 405 2016 146 102 10 77 10 345 2015 133 106 12 90 11 352 Technical Committee From time to time, we also utilize the services of independent contractors The Technical Committee is composed of three directors along with the to perform various field and other services as needed. As of December 31, Chief Operating Officer. The members of the Technical Committee are Mr. 2017, 37 of our employees were represented by labor unions or covered Carlos Gulisano (who serves as Chairman of the committee), Mr. Gerald by collective bargaining agreements. We believe that relations with our O´Shaughnessy, Mr. James F. Park and Mr. Augusto Zubillaga. employees are satisfactory. The Technical Committee’s responsibilities include: (a) overseeing the E. Share ownership technical studies and evaluations of the Company’s properties and proposals As of March 15, 2018, members of our board of directors and our senior to acquire new properties and/or relinquish existing ones as well as reviewing management held as a group 20,881,731 of our common shares and 34.5% of project plans; (b) reviewing the Annual Reserve Report, the Company’s our outstanding share capital. environmental programs and their effectiveness and the Company’s health and safety program and its effectiveness; and (c) providing a forum for ideas The following table shows the share ownership of each member of our board and solutions for the key technical people within the Company. of directors and senior management as of March 15, 2018. Common Percentage of outstanding Disclosure Committee The Disclosure Committee is composed of Mr. James F. Park, Mr. Andrés Ocampo, and certain other officers or managers per request. The Disclosure Committee’s responsibilities include (a) review and approval of Shareholder James F. Park(1) Gerald E. O’Shaughnessy(2) Juan Cristóbal Pavez(3) Carlos Gulisano filings with the SEC and press releases, (b) review of presentations to analysts, Pedro E. Aylwin Chiorrini investors and rating agencies and (c) establishment of disclosure controls and Robert Bedingfield procedures. Liability insurance Jamie B. Coulter Augusto Zubillaga Alberto Matamoros We maintain liability insurance coverage for all of our directors and officers, Marcela Vaca the level of which is reviewed annually. D. Employees Barbara Bruce Carlos Murut Salvador Minniti Stacy Steimel As of December 31, 2017, we had 405 employees, representing an increase of Horacio Fontana 17% from December 31, 2016. Agustina Wisky Guillermo Portnoi Andrés Ocampo shares 7,891,269 7,213,316 2,964,162 193,327 220,859 82,495 1,517,587 * * * * * * * * * * * Sub-total senior management ownership of less than 1% Total 798,716 20,881,731 common shares 13.0% 11.9% 4.9% 0.3% 0.4% 0.1% 2.5% * * * * * * * * * * * 1.3% 34.5% GeoPark 133 Major shareholders and related party transactions * Indicates ownership of less than 1% of outstanding common shares. the table is based solely on the disclosure set forth in Mr. O’Shaughnessy’s most (1) Held 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 recent Schedule 13G filed with the SEC on February 13, 2018. (3) Held directly and indirectly through Manchester Financial Group, L.P., Manchester Financial Group, Inc., Douglas F. Manchester and Papa Doug Trust Mr. Park does not reflect the 1,533,927 common shares held as of March 15, u/t/d/ January 11, 2010. This information is based solely on the disclosure set 2018 in the employee benefit trust described under “Item 6. Directors, forth in Manchester Financial Group, L.P.’s most recent Schedule 13G filed with Senior Management and Employees—B. Compensation— Stock Awards Plan.” 1,073,201 of these common shares have been pledged pursuant to lending arrangements. The information set forth above is based solely on the SEC on February 8, 2017. (4) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the credit officers, managers and legal staff. This information is based solely on the SEC on February 13, 2018. (2) Held directly and indirectly through GP Investments LLP, GPK Holdings LLC and other investment vehicles. 6,975,957 of these common shares have disclosure set forth in the IFC’s most recent Schedule 13G/A filed with the SEC on March 23, 2018. (5) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 86,358 been pledged pursuant to lending arrangements. The information set forth common shares held by him personally. above is based solely on the disclosure set forth in Mr. O’Shaughnessy’s most recent Schedule 13G filed with the SEC on February 13, 2018. Principal shareholders do not have any different or special voting rights in comparison to any other common shareholder. (3) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez According to our transfer agent, as of February 28, 2018, we had 22 registered include 86,358 common shares held by him personally. shareholders, out of which 6 are registered as U.S. shareholders. Since some of the shares are held by nominees, the number of shareholders may not be ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS representative of the number of beneficial owners. A. Major shareholders B. Related party transactions The following table presents the beneficial ownership of our common shares We have entered into the following transactions with related parties: as of March 15, 2018: Common Percentage of outstanding In 2010, we formed a strategic partnership with LGI to acquire and develop LGI Chile Shareholders’ Agreements Shareholder James F. Park(1) Gerald E. O’Shaughnessy(2) Manchester Financial Group, L.P.(3) IFC Equity Investments(4) Juan Cristóbal Pavez(5) Other shareholders Total shares 7,891,269 7,193,316 5,103,439 2,998,633 2,964,162 34,439,653 60,606,787 common shares jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired 13.0% 11.9% 8.4% 4.9% 4.9% a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark TdF, for a total consideration of US$148.0 million, plus additional equity funding of US$18.0 million through 2014. On May 20, 2011, in connection with LGI’s investment in GeoPark Chile, we and LGI entered into the LGI Chile Shareholders’ Agreements, setting forth our and LGI’s respective rights and 56.8% obligations in connection with LGI’s investment in our Chilean oil and gas 100.0% business. Specifically, the LGI Chile Shareholders’ Agreements provide that the boards of each of GeoPark Chile and GeoPark TdF will consist of four (1) Held 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 directors; as long as LGI holds at least 5% of the voting shares of GeoPark Chile or GeoPark TdF, as applicable, LGI has the right to elect one director and such reflect the 1,533,927 common shares held as of March 15, 2018 in the employee director’s alternate, while the remaining directors, and alternates, are elected benefit trust described under “Item 6. Directors, Senior Management and by us. Additionally, the agreements require the consent of LGI or its appointed Employees—B. Compensation— Stock Awards Plan.” 1,073,201 of these common director in order for GeoPark Chile or GeoPark TdF, as applicable, to be able shares have been pledged pursuant to lending arrangements. The information to take certain actions, including, among others: making any decision to set forth above and listed in the table is based solely on the disclosure set forth in terminate or permanently or indefinitely suspend operations in or surrender Mr. Park’s most recent Schedule 13G filed with the SEC on February 13, 2018. (2) Held directly and indirectly through GP Investments LLP, GPK Holdings LLC and other investment vehicles. 6,975,957 of these common shares have been pledged our blocks in Chile (other than as required under the terms of the relevant CEOP for such blocks); selling our blocks in Chile to our affiliates; making any change to the dividend, voting or other rights that would give preference to pursuant to lending arrangements. The information set forth above and listed in or discriminate against the shareholders of these companies; entering into certain related party transactions; and creating a security interest over our 134 GeoPark 20-F blocks in Chile (other than in connection with a financing that benefits our the other shareholder before selling those shares to a third party; and (ii) any Chilean subsidiaries). The LGI Chile Shareholders’ Agreements also provide sale to a third party is subject to tag-along and drag-along rights, and the that: (i) if LGI or either Agencia or GeoPark Chile decides to sell its shares in non-transferring shareholder has the right to object to a sale to the third-party GeoPark Chile or GeoPark TdF, as applicable, the transferring shareholder if it considers such third-party to be not of a good reputation or one of our must make an offer to sell those shares to the other shareholder before selling direct competitors. We and LGI also agreed to vote our common shares or them to a third party; and (ii) any sale to a third party is subject to tag-along otherwise cause GeoPark Colombia to declare dividends only after allowing and drag-along rights, and the non-transferring shareholder has the right to for retentions for approved work programs and budgets, capital adequacy and object to a sale to the third-party if it considers such third-party to be not of tied surplus requirements of GeoPark Colombia, working capital requirements, a good reputation or one of our direct competitors. We and LGI also agreed banking covenants associated with any loan entered into by GeoPark to vote our common shares or otherwise cause GeoPark Chile or GeoPark TdF, Colombia or our other Colombian subsidiaries and operational requirements. as applicable, to declare dividends only after allowing for retentions to meet anticipated future investments, costs and obligations. See “Item 4. Information In addition, our agreement with LGI in Colombia allows us to earn back up on the Company—B. Business Overview—Significant Agreements— to 12% of our equity participation in GeoPark Colombia, following certain Agreements with LGI—LGI Chile Shareholders’ Agreements.” recovery factors of LGI `s initial investments as follows: (i) if the recovery LGI Colombia Agreements factor is between one and two times, our incremental equity share is 4%; if the recovery factor is between two to three, three to four, four to five, and On December 18, 2012, we, Agencia, GeoPark Colombia and LGI entered above five, our incremental equity increases by an additional 2% each time, into the LGI Colombia Shareholders’ Agreement and a subscription share for up to a 12%, so that LGI participation could be reduced from current 20% agreement, pursuant to which LGI acquired a 20% interest in GeoPark to 8%. Recovery factor is measured considering realized dividends or other Colombia SAS. Further, on January 8, 2014, following an internal corporate distributions over the original investments. reorganization of our Colombian operations, GeoPark Colombia Coöperatie U.A. and GeoPark Latin America entered into a new members’ agreement See “Item 4. Information on the Company—B. Business Overview—Significant with LGI (the “LGI Colombia Members’ Agreement”), that sets out substantially Agreements—Agreements with LGI—LGI Colombia Agreements.” similar rights and obligations to the LGI Colombia Shareholders’ Agreement in respect of our oil and gas business in Colombia. We refer to the LGI Colombia IFC Subscription and Shareholders’ Agreement Shareholders’ Agreement and the LGI Colombia Members’ Agreement On February 7, 2006, in order to finance the exploration, development collectively as the LGI Colombia Agreements. The LGI Colombia Members’ and exploitation of our blocks in Chile and Argentina and the acquisition Agreements provide that the board of GeoPark Colombia Coöperatie U.A. of additional exploration, development and exploitation blocks in Latin will consist of four directors; as long as LGI holds at least 14% of GeoPark America, we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead Colombia SAS, LGI has the right to elect one director and such director’s Investors, entered into an agreement (the “IFC Subscription and Shareholders’ alternate, while the remaining directors, and alternates, are elected by us. Agreement”), pursuant to which IFC agreed to subscribe and pay for 2,507,161 Additionally, the LGI Colombia Agreements require the consent of LGI or the of our common shares, representing approximately 10.5% of our then- LGI appointed director for GeoPark Colombia SAS to be able to take certain outstanding common shares, at an aggregate subscription price of US$10.0 actions, including, among others: making any decision to terminate or million (or approximately US$3.99 per common share). permanently or indefinitely suspend operations in or surrender our blocks in Colombia (other than as required under the terms of the relevant concessions We agreed, for so long as IFC is a shareholder in the company, among for such blocks); creating a security interest over our blocks in Colombia; other things, to: ensure that our operations are in compliance with certain approving of GeoPark Colombia SAS’ annual budget and work programs and environmental and social guidelines; appoint and maintain a technically the mechanisms for funding any such budget or program; entering into any qualified individual to be responsible for the environmental and social borrowings other than those provided in an approved budget or incurred in management of our activities; maintain certain forms of insurance coverage, the ordinary course of business to finance working capital needs; granting including coverage for public liability and director’s and officer’s liability any guarantee or indemnity to secure liabilities of parties other than those reasonably acceptable to IFC, and in respect of certain of our operations; of our Colombian subsidiaries; changing the dividend, voting or other rights not undertake certain prohibited activities; and ensure that no prohibited that would give preference to or discriminate against the shareholders of payments are made by us or on our or the Lead Investors’ behalf, in respect of GeoPark Colombia SAS; entering into certain related party transactions; and our operations. disposing of any material assets other than those provided for in an approved budget and work program. The LGI Colombia Agreements also provide that: We also agreed to provide to IFC, within 30 days of the end of the first half (i) if either we or LGI decide to sell our respective shares in GeoPark Colombia of the year, copies of our unaudited consolidated financial statements for SAS, the transferring shareholder must make an offer to sell those shares to the period (prepared under IFRS), a report on our capital expenditures for GeoPark 135 the period, a comprehensive report on the progress of the exploration, employment, commercial, environmental, safety and health matters. For development and exploitation of our blocks in Latin America and a statement example, from time to time, we receive notice of environmental, health and of all related party transactions during the period, with a certification by a safety violations. It is not presently possible to determine whether any such company officer that these were on an arm’s-length basis; within 90 days matters will have a material adverse effect on our consolidated financial of the end of our fiscal year, copies of our audited consolidated financial position and results of operations. statements for the year (prepared under IFRS), a management letter from our auditors in respect of our financial control procedures, accounting and In Brazil, GeoPark Brasil is a party to a class action filed by the Federal management information systems and any litigation, an annual monitoring Prosecutor’s Office regarding a concession agreement of exploratory Block report confirming compliance with national or local requirements and the PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil environmental and social requirements mandated by the agreement, a and gas bidding round held in November 2013. The Brazilian Federal Court report indicating any payments in the year to any governmental authority in issued an injunction against the ANP and GeoPark Brasil in December 2013 connection with the documents governing our Chilean and Argentine blocks that prohibited GeoPark Brasil’s execution of the concession agreement and certificates of insurance, with a certificate of our insurer confirming that until the ANP conducted studies on whether drilling for unconventional effectiveness of our policies and payment of all applicable premiums; within resources would contaminate the dams and aquifers in the region. On July 45 days before each fiscal year begins, a proposed annual business plan and 17, 2015, GeoPark Brasil, at the instruction of the ANP, signed the concession budget for the upcoming year; within 3 days after its occurrence, notification agreement, which included a clause prohibiting GeoPark Brasil from of any incident that had or may reasonably be expected to have an adverse conducting unconventional exploration activity in the area. Despite the effect on the environment, health or safety; copies of notices, reports or other clause containing the prohibition, the judge in the case concluded that the communications between us and our board of directors or shareholders; and, concession agreement should not be executed. Thus, GeoPark Brasil requested within five days of receipt thereof, copies of any reports, correspondence, that the ANP comply with the decision and annul the concession agreement, documentation or notices from any third-party, governmental authority or which the ANP´s Board did on October 9, 2015. The annulment reverted the state-owned company that could reasonably be expected to materially impact status of all parties to the status quo ante, which maintains GeoPark Brasil’s our operations. Mr. O’Shaughnessy and Mr. Park have also agreed to procure right to the block. that shareholders holding 51% of our common shares cause us to comply with the covenants above. Dividends and dividend policy Holders of common shares will be entitled to receive dividends, if any, paid on Executive Directors’ Service Agreements the common shares. We have entered into service contracts with certain of our executive directors. See “Item 6. Directors, Senior Management and Employees—B. We have never declared or paid any cash dividends on our common shares. Compensation—Executive compensation—Director Contracts.” We intend to retain all of our future earnings, if any, generated by our For further information relating to our related party transactions and balances do not expect to pay cash dividends on our common shares in the foreseeable outstanding as of December 31, 2017, 2016 and 2015, please see Note 33 to future. Because we are a holding company with no direct operations, we will operations for the development and growth of our business. Accordingly, we our Consolidated Financial Statements. C. Interests of Experts and Counsel 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 us from paying dividends. Mainly resulting from the impact of the decline in oil prices, we have recorded accumulated losses amounting to US$283.9 million as of December 31, 2017, which further limits our ability to pay ITEM 8. FINANCIAL INFORMATION dividends in the foreseeable future. A. Consolidated statements and other financial information Under the Bermuda Companies Act, we may not declare or pay a dividend Financial statements if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the See “Item 18. Financial Statements,” which contains our audited financial realizable value of our assets would thereafter be less than our liabilities. We statements prepared in accordance with IFRS. do not presently have any reasonable grounds for believing that, if we were Legal proceedings to declare or pay a dividend on our common shares outstanding, we would thereafter be unable to pay our liabilities as they became due or that the From time to time, we may be subject to various lawsuits, claims and realizable value of our assets would thereafter be less than our liabilities. proceedings that arise in the normal course of business, including Additionally, any decision to pay dividends in the future, and the amount 136 GeoPark 20-F of any distributions, is at the discretion of our board of directors and our shareholders, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. See “Item 3. Key Information—D. Risk factors—Risks related to our High Low (US$ per share) Common shares Average daily trading volume (in shares) common shares—We have never declared or paid, and do not intend to Annual price history pay in the foreseeable future, cash dividends on our common shares, and, 2014 (from February 7 consequently, your only opportunity to achieve a return on your investment through December 31, 2014) 11.00 is if the price of our stock appreciates” and “—We are a holding company dependent upon dividends from our subsidiaries, which may be limited by law and by contract from making distributions to us, which would affect our 2015 2016 2017 financial condition, including the ability to pay dividends on the common 2018 (through April 6, 2018) shares,” as well as “Item 10. Additional Information—B. Memorandum of Quarterly price history association and bye-laws.” B. Significant changes 1st Quarter 2017 2nd Quarter 2017 3rd Quarter 2017 4th Quarter 2017 A discussion of the significant changes in our business can be found under 1st Quarter 2018 “Item 4. Information on the Company—B. Business Overview.” 2nd Quarter 2018 5.59 5.06 10.05 12.58 7.18 8.89 9.52 10.05 12.40 4.92 2.70 2.25 4.50 9.24 4.50 6.55 7.54 8.05 9.24 ITEM 9. THE OFFER AND LISTING Monthly price history (through April 6, 2018) 12.58 12.18 A. Offering and listing details Not applicable. B. Plan of distribution Not applicable. C. Markets November 2017 December 2017 January 2018 February 2018 March 2018 April 2018 9.83 10.05 10.88 10.36 12.40 8.48 8.60 9.60 9.24 9.35 (through April 6, 2018) 12.58 12.18 On February 6, 2014 we completed our initial public offering and listed our common shares on the NYSE. Source: NYSE Connect Our common shares have been listed on the NYSE under the symbol “GPRK” D. Selling shareholders since February 7, 2014. They were previously listed on the AIM under the Not applicable. symbol “GPK” until February 19, 2014, and, from 2009 to 2015 had been admitted to trade on the Santiago Offshore Stock Exchange (Bolsa Offshore de E. Dilution la Bolsa de Comercio de Santiago). Not applicable. The table below presents, for the periods indicated, the annual, quarterly and F. Expenses of the issue monthly high and low closing prices (in US$) of our common shares on the Not applicable. NYSE. 47,795 23,838 103,283 142,158 162,292 149,187 202,151 115,768 101,643 153,916 264,481 142,290 72,795 125,886 108,468 223,067 264,481 ITEM 10. ADDITIONAL INFORMATION A. Share capital Not applicable. B. Memorandum of association and bye-laws The following description of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws. GeoPark 137 General preference on any outstanding preference shares. We are an exempted company with limited liability incorporated under the laws of Bermuda with registration number 33273 from the Registrar of Companies. Board composition The rights of our shareholders will be governed by Bermuda law and by our Our bye-laws provide that our board of directors will determine the memorandum of association and bye-laws. Bermuda company law differs maximum size of the board, provided that it shall be not be composed of 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 138 GeoPark 20-F Act also imposes a duty on directors of a Bermuda company, to act honestly directors or by a vote of shareholders, in each case if the material facts as to and in good faith, with a view to the best interests of the company, and to the interested director’s relationship or interests are disclosed or are known to exercise the care, diligence and skill that a reasonably prudent person would the disinterested directors or shareholders, or such contract or arrangement exercise in comparable circumstances. In addition, the Bermuda Companies is fair to the corporation as of the time it is approved or ratified. Additionally, Act imposes various duties on directors with respect to certain matters of such interested director could be held liable for a transaction in which such management and administration of the company. director derived an improper personal benefit. 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 The duty of care requires that directors act in an informed and deliberate directors in defending any civil or criminal proceeding against them on the manner and to inform themselves, prior to making a business decision, of condition that the officers and directors repay the monies if any allegation all relevant material information reasonably available to them. The duty of of fraud or dishonesty is proved against them provided, however, that, if care also requires that directors exercise care in overseeing the conduct of the Bermuda Companies Act requires, an advancement of expenses shall be corporate employees. The duty of loyalty is the duty to act in good faith, not made only upon delivery to the Company of an undertaking, by or on behalf out of self-interest, and in a manner which the director reasonably believes of such indemnitee, to repay all amounts so advanced if it shall ultimately to be in the best interests of the shareholders. A party challenging the be determined by final judicial decision from which there is no further propriety of a decision of a board of directors bears the burden of rebutting right to appeal that such indemnitee is not entitled to be indemnified for the presumptions afforded to directors by the “business judgment rule.” If such expenses under this Bye-law or otherwise. Our bye-laws provide that the presumption is not rebutted, the business judgment rule attaches to the company and the shareholders waive all claims or rights of action that protect the directors and their decisions. Where, however, the presumption is they might have, individually or in right of the company, against any of the rebutted, the directors bear the burden of demonstrating the fairness of the company’s directors or officers for any act or failure to act in the performance relevant transaction. Notwithstanding the foregoing, Delaware courts subject of such director’s or officers’ duties, except with respect to any fraud or directors’ conduct to enhanced scrutiny in respect of defensive actions taken dishonesty, or to recover any gain, personal profit or advantage to which such in response to a threat to corporate control and approval of a transaction director is not legally entitled. 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 Pursuant to our bye-laws, a director shall declare the nature of his interest in meeting of shareholders each calendar year, unless the shareholders in any contract or arrangement with the company as required by the Bermuda a general meeting, elect to dispense with the holding of annual general Companies Act. A director so interested shall not, except in particular meetings. Under Bermuda law and our bye-laws, a special general meeting of circumstances set out in our bye-laws, be entitled to vote or be counted in the shareholders may be called by the board of directors and may be called upon quorum at a meeting in relation to any resolution in which he has an interest, the requisition of shareholders holding not less than 10% of the paid-up capital which is to his knowledge, a material interest (otherwise than by virtue of of the company carrying the right to vote at general meetings of shareholders. his interest in shares or debentures or other securities of or otherwise in or through the company). A director will be liable to us for any secret profit Our bye-laws provide that, at any general meeting of the shareholders, the realized from the transaction. In contrast, under Delaware law, such a contract presence in person or by proxy of two or more shareholders representing in or arrangement is voidable unless it is approved by a majority of disinterested excess of 50% of the total issued voting shares of the company shall constitute GeoPark 139 a quorum for the transaction of business unless the company only has one vote in person or by proxy at any general meeting of the shareholders in shareholder, in which case such shareholder shall constitute a quorum. Unless accordance with the provisions of the bye-laws. Under Bermuda law, in the otherwise required by law or by our bye-laws, shareholder action requires a event of an amalgamation or merger of a Bermuda company with another resolution adopted by a majority of votes cast by shareholders at a general company or corporation, a shareholder who did not vote in favor of the meeting at which a quorum is present. Shareholder proposals amalgamation or merger and who is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of the notice of the shareholders meeting, apply to the Supreme Court of Bermuda to 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, 140 GeoPark 20-F a company cannot purchase its own shares if there are reasonable grounds for admission of its common shares on AIM. Because the following statements believing that the company is, or after the repurchase would be, unable to pay are summaries, they do not discuss all aspects of Bermuda law that may be its liabilities as they become due. relevant to us and our shareholders. Shareholder suits Interested Directors . Under our bye-laws and the Bermuda Companies Act, a Class actions and derivative actions are generally not available to director shall declare the nature of his interest in any contract or arrangement shareholders under Bermuda law. The Bermuda courts, however, would with the company. Our bye-laws further provide that a director so interested ordinarily be expected to permit a shareholder to commence an action shall not, except in particular circumstances, be entitled to vote or be counted in the name of a company to remedy a wrong to the company where in the quorum at a meeting in relation to any resolution in which he has an the act complained of is alleged to be beyond the corporate power of interest, which is to his knowledge, a material interest (otherwise than by the company or illegal, or would result in the violation of the company’s virtue of his interest in shares or debentures or other securities of or otherwise memorandum of association or bye-laws. Furthermore, consideration in or through the company). A director will be liable to us for any secret profit would be given by a Bermuda court to acts that are alleged to constitute realized from the transaction. See “Item 10—B. Memorandum of association a fraud against the minority shareholders or where an act requires the 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 Bermuda fiduciary duty, except in respect of any fraud or dishonesty of such director company who did not vote in favor of the amalgamation or merger and who is or officer. not satisfied that he has been offered fair value for his shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Comparison of Bermuda law to Delaware corporate law 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 GeoPark 141 of the company or illegal, or would result in the violation of the company’s proceeding, such director or officer had no reasonable cause to believe his memorandum of association or bye-laws. When the affairs of a company or her conduct was unlawful. In addition, we have entered into customary are being conducted in a manner which is oppressive or prejudicial to the indemnification agreements with our directors. interests of some part of the shareholders, one or more shareholders may apply for an order of the Supreme Court of Bermuda regulating the conduct As a result of these differences, investors could have more difficulty of the company’s affairs in the future or an order to purchase the shares of protecting their interests than would shareholders of a corporation any shareholders by other shareholders or by the company and, in the case of incorporated in the United States. a purchase by the company, for the reduction accordingly of the company’s capital, or otherwise. See “Item 10—B. Memorandum of association and bye- Tax matters . Under current Bermuda law, we are not subject to tax on laws—Shareholder Suits.” income or capital gains. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, Our bye-laws contain a provision by virtue of which we and our shareholders an assurance that, in the event that Bermuda enacts legislation imposing waive any claim or right of action that they have, both individually and on tax computed on profits, income, any capital asset, gain or appreciation, our behalf, against any director or officer in relation to any action or failure to or any tax in the nature of estate duty or inheritance, then the imposition take action by such director or officer, including the breach of any fiduciary of any such tax shall not be applicable to us or to any of our operations or duty, except in respect of any fraud or dishonesty of such director or officer. shares, debentures or other obligations, until March 31, 2035. We could be Class actions and derivative actions generally are available to shareholders subject to taxes in Bermuda after that date. This assurance is subject to the under Delaware law for, among other things, breach of fiduciary duty, provision that it is not to be construed to prevent the application of any tax corporate waste and actions not taken in accordance with applicable law. In or duty to such persons as are ordinarily resident in Bermuda or to prevent such actions, the court has discretion to permit the winning party to recover the application of any tax payable in accordance with the provisions of the attorneys’ fees incurred in connection with such action. Land Tax Act 1967 or otherwise payable in relation to any property leased Indemnification of Directors . We may indemnify our directors and officers in pay annual Bermuda government fees. In addition, all entities employing their capacity as directors or officers for any loss arising or liability attaching individuals in Bermuda are required to pay a payroll tax and there are other to them by virtue of any rule of law in respect of any negligence, default, sundry taxes payable, directly or indirectly, to the Bermuda government. breach of duty or breach of trust of which a director or officer may be Neither we nor our Bermuda subsidiaries employ individuals in Bermuda as to us. We are incorporated in Bermuda as an exempted company and guilty in relation to the company other than in respect of his own fraud or at the date of this 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, the general public without charge. A company is required to maintain its to repay all amounts if it shall ultimately be determined by final decision share register in Bermuda but may, subject to the provisions of the Bermuda that such indemnitee is not entitled to be indemnified for such expenses Companies Act, establish a branch register outside of Bermuda. Bermuda under our Bye-laws or otherwise. Under Delaware law, a corporation law does not, however, provide a general right for shareholders to inspect or may indemnify a director or officer of the corporation against expenses obtain copies of any other corporate records. (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding Registrar or transfer agent by reason of such position if such director or officer acted in good faith and A register of holders of the common shares is maintained by Coson Corporate in a manner he or she reasonably believed to be in or not opposed to the Services Limited in Bermuda, and a branch register is maintained in the best interests of the corporation and, with respect to any criminal action or United States by Computershare Trust Company, N.A., who serves as branch registrar and transfer agent. 142 GeoPark 20-F Enforcement of Judgments Section 98 further provides that a Bermuda company may indemnify its We are incorporated as an exempted company with limited liability directors, officers and auditors against any liability incurred by them in under the laws of Bermuda, and substantially all of our assets are located defending any proceedings, whether civil or criminal, in which judgment in Colombia, Chile, Brazil, Peru and Argentina. In addition, most of our is awarded in their favor or in which they are acquitted or granted relief by directors and executive officers reside outside the United States, and all or the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda a substantial portion of the assets of such persons are located outside the Companies Act. United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United Our bye-laws contain provisions whereby we and our shareholders waive States judgments obtained in U.S. courts against us or those persons based any claim or right of action that we have, both individually and on our behalf, on the civil liability provisions of the U.S. securities laws. against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of There is no treaty in force between the United States and Bermuda providing such director or officer. We may also indemnify our directors and officers for the reciprocal recognition and enforcement of judgments in civil in their capacity as directors and officers for any loss arising or liability and commercial matters. As a result, whether a U.S. judgment would be 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 default, breach of trust of which a director or officer may be guilty in relation on whether the U.S. court that entered the judgment is recognized by the to the company other than in respect of his own fraud or dishonesty. We Bermuda court as having jurisdiction over us or our directors and officers, as have entered into customary indemnification agreements with our directors. determined by reference to Bermuda conflict of law rules and the judgment is not contrary to public policy in Bermuda, has not been obtained by fraud No treaty exists between the United States and Chile for the reciprocal in proceedings contrary to natural justice and is not based on an error recognition and enforcement of foreign judgments. Chilean courts, however, in Bermuda law. A judgment debt from a U.S. court that is final and for a have enforced valid and conclusive judgments for the payment of money sum certain based on U.S. federal securities laws will not be enforceable in rendered by competent U.S. courts by virtue of the legal principles of Bermuda unless the judgment debtor had submitted to the jurisdiction of reciprocity and comity, subject to review in Chile of the U.S. judgment in the U.S. court, and the issue of submission and jurisdiction is a matter of order to ascertain whether certain basic principles of due process and public Bermuda (not U.S.) law. policy have been respected, without retrial or review of the merits of the subject matter. If a U.S. court grants a final judgment, enforceability of this An action brought pursuant to a public or penal law, the purpose of which is judgment in Chile will be subject to obtaining the relevant exequatur (i.e., the enforcement of a sanction, power or right at the instance of the state in recognition and enforcement of the foreign judgment) according to Chilean its sovereign capacity, may not be entertained by a Bermuda court. Certain civil procedure law in effect at that time, and depending on certain factors remedies available under the laws of U.S. jurisdictions, including certain (the satisfaction or non-satisfaction of which would be determined by the remedies under U.S. federal securities laws, may not be available under Supreme Court of Chile). Currently, the most important of such factors are: Bermuda law or enforceable in a Bermuda court, as they may be contrary the existence of reciprocity (if it can be proved that there is no reciprocity to Bermuda public policy. Further, no claim may be brought in Bermuda in the recognition and enforcement of the foreign judgment between the against us or our directors and officers in the first instance for violations United States and Chile, that judgment would not be enforced in Chile); the of U.S. federal securities laws because these laws have no extraterritorial absence of any conflict between the foreign judgment and Chilean laws jurisdiction under Bermuda law and do not have force of law in Bermuda. A (excluding for this purpose the laws of civil procedure) and Chilean public Bermuda court may, however, impose civil liability on us or our directors and policy; the absence of a conflicting judgment by a Chilean court relating officers if the facts alleged in a complaint constitute or give rise to a cause of to the same parties and arising from the same facts and circumstances; action under Bermuda law. However, section 281 of the Bermuda Companies the Chilean court’s determination that the U.S. courts had jurisdiction, that Act allows a Bermuda court, in certain circumstances, to relieve officers and process was appropriately served on the defendant and that the defendant directors of Bermuda companies of liability for acts of negligence, breach of was afforded a real opportunity to appear before the court and defend its duty or trust or other defaults. case; and the judgment being final under the laws of the country in which it was rendered. Nonetheless, we have been advised by our Chilean counsel Section 98 of the Bermuda Companies Act provides generally that a Bermuda that there is doubt as to the enforceability in original actions in Chilean company may indemnify its directors, officers and auditors against any courts of liabilities predicated solely upon U.S. federal or state securities laws. liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, C. Material contracts except in cases where such liability arises from fraud or dishonesty of which See “Item 4. Information on the Company—B. Business Overview—Significant such director, officer or auditor may be guilty in relation to the company. Agreements.” GeoPark 143 D. Exchange controls Not applicable. E. Taxation • a person holding common shares in connection with a trade or business conducted outside of the United States. If an entity that is classified as a partnership for U.S. federal income tax The following summary contains a description of certain Bermudian, U.S. purposes holds common shares, the U.S. federal income tax treatment of a federal income, and Chilean tax consequences of the acquisition, ownership and partner will generally depend on the status of the partner and the activities disposition of our common shares. The summary is based upon the tax laws of of the partnership. Partnerships holding common shares and partners in such Bermuda, the United States, and Chile, and regulations thereunder as of the date partnerships should consult their tax advisers as to the particular U.S. federal hereof, which are subject to change. income tax consequences of their investment in our common shares. Bermuda tax consideration This discussion is based on the Internal Revenue Code of 1986, as amended At the date of this annual report, there is no Bermuda income or profits tax, (the “Code”), administrative pronouncements, judicial decisions, and final, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance temporary and proposed Treasury regulations, all as of the date hereof, any tax payable by us or by our shareholders in respect of our common shares. We of which is subject to change, possibly with retroactive effect. U.S. Holders have obtained an assurance from the Minister of Finance of Bermuda under should consult their tax advisers concerning the U.S. federal, state, local and the Exempted Undertakings Tax Protection Act 1966 that, in the event that foreign tax consequences of owning and disposing of our common shares in any legislation is enacted in Bermuda imposing any tax computed on profits their particular circumstances. or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 31, A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal 2035, be applicable to us or to any of our operations or to our common shares, income tax purposes that is: debentures or other obligations except insofar as such tax applies to persons • a citizen or individual resident of the United States; ordinarily resident in Bermuda or is payable by us in respect of real property • a corporation, or other entity taxable as a corporation, created or organized owned or leased by us in Bermuda. We pay annual Bermuda government fees. in or under the laws of the United States, any state therein or the District of Columbia; or Material U.S. federal income tax considerations • an estate or trust the income of which is subject to U.S. federal income The following is a description of the material U.S. federal income tax taxation regardless of its source. consequences to U.S. Holders (as defined below) of owning and disposing of our common shares. This discussion is not a comprehensive description of This discussion assumes that we are not, and will not become, a passive all tax considerations that may be relevant to a particular person’s decision foreign investment company, as described below. to hold our common shares. This discussion applies only to a U.S. Holder that holds our common shares as capital assets for tax purposes. In addition, it Taxation of distributions does not describe all of the tax consequences that may be relevant in light of Distributions paid on our common shares, other than certain pro rata the U.S. Holder’s particular circumstances, including alternative minimum tax distributions of common shares, will generally be treated as dividends to and Medicare contribution tax consequences and differing tax consequences the extent paid out of our current or accumulated earnings and profits (as applicable to a U.S. Holder subject to special rules, such as: determined under U.S. federal income tax principles). Because we do not • certain financial institutions; maintain calculations of our earnings and profits under U.S. federal income tax • a dealer or trader in securities who uses a mark-to-market method of tax principles, it is expected that distributions will generally be reported to U.S. accounting; Holders as dividends. Subject to the passive foreign investment company rules • a person holding common shares as part of a straddle, wash sale or described below, dividends paid by qualified foreign corporations to certain non- conversion transaction or entering into a constructive sale with respect to the corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is common shares; treated as a qualified foreign corporation with respect to dividends paid on stock • a person whose functional currency for U.S. federal income tax purposes is that is readily tradable on a securities market in the United States, such as the not the US$; NYSE where our common shares are traded. Non-corporate U.S. Holders should • a partnership or other entities classified as partnerships for U.S. federal consult their tax advisers to determine whether the favorable rate will apply to income tax purposes; dividends they receive and whether they are subject to any special rules that • a tax-exempt entity, including an “individual retirement account” or “Roth IRA;” limit their ability to be taxed at this favorable rate. • a person that owns or is deemed to own 10% or more of our voting stock; • a person who acquired our shares pursuant to the exercise of an employee A dividend generally will be included in a U.S. Holder’s income when received, stock option or otherwise as compensation; or 144 GeoPark 20-F will be treated as foreign-source income to U.S. Holders and will not be eligible be available and, if so, what the consequences of the alternative treatments for the dividends-received deduction generally available to U.S. corporations would be in their particular circumstances. under the Code with respect to dividends paid by domestic corporations. Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were Sale or other taxable disposition of common shares treated as a PFIC for the taxable year in which we paid a dividend or the prior Gain or loss realized on the sale or other taxable disposition of our common taxable year, the preferential dividend rates discussed above with respect to shares will be capital gain or loss, and will be long-term capital gain or loss if dividends paid to certain non-corporate U.S. Holders would not apply. the U.S. Holder held our common shares for more than one year. Long-term capital gain of a non-corporate U.S. Holder is generally taxed at preferential Information reporting and backup withholding rates. The deductibility of capital losses is subject to limitations. The amount Payments of dividends and sales proceeds that are made within the United of the gain or loss will equal the difference between the U.S. Holder’s tax States or through certain U.S.-related financial intermediaries generally are basis in the common shares disposed of and the amount realized on the subject to information reporting, and may be subject to backup withholding, disposition. If a Chilean tax is withheld on the sale or disposition of the unless (1) the U.S. Holder is a corporation or other exempt recipient or common shares, a U.S. Holder’s amount realized will include the gross (2) in the case of backup withholding, the U.S. Holder provides a correct amount of the proceeds of the sale or disposition before deduction of the taxpayer identification number and certifies that it is not subject to backup Chilean tax. See “—Chilean tax on transfers of shares” for a description of withholding. The amount of any backup withholding from a payment to a when a disposition may be subject to taxation by Chile. This gain or loss U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal will generally be U.S.-source gain or loss for foreign tax credit purposes. U.S. income tax liability and may entitle it to a refund, provided that the required Holders should consult their tax advisers as to whether the Chilean tax on information is timely furnished to the Internal Revenue Service. gains may be creditable against the U.S. Holder’s U.S. federal income tax on foreign-source 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. 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes on We believe that we were not a “passive foreign investment company,” or PFIC, the indirect transfer of shares, equity rights, interests or other rights in the for U.S. federal income tax purposes for 2017, and we do not expect to be equity, control or profits of a Chilean entity as well as transfers of other assets a PFIC in the foreseeable future. However, because the composition of our and property of permanent establishments or other businesses in Chile. The income and assets will vary over time, there can be no assurance that we will 2014 tax reform introduces a measure which obliges the company from which not be a PFIC for any taxable year. The determination of whether we are a PFIC shares are transferred to pay taxes if the entity which undertakes the transfer is made annually and is based upon the composition of our income and assets of shares fails to do so. (including the income and assets of, among others, entities in which we hold at least a 25% interest), and the nature of our activities. The indirect transfer rules apply to sales of shares of an entity: • If such entity is an offshore holding company located in a black-listed If we were a PFIC for any taxable year during which a U.S. Holder held our tax haven jurisdiction as determined by Chilean tax law, or a black-listed common shares, gain recognized by a U.S. Holder on a sale or other disposition jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean (including certain pledges) of our common shares would generally be resident holds 5% or more of such entity, or such entity’s rights to equity, allocated ratably over the U.S. Holder’s holding period for the common shares. control or profits, or 50% or more of such entity’s rights to equity or profits are The amounts allocated to the taxable year of the sale or other disposition held by residents in black-listed jurisdictions; or and to any year before we became a PFIC would be taxed as ordinary income. • the shares or rights transferred represent 10% or more of the offshore The amount allocated to each other taxable year would be subject to tax holding company (considering dispositions by related persons and over the at the highest rate in effect for individuals or corporations for that year, as preceding 12-month period) and the underlying Chilean Assets indirectly appropriate, and an interest charge would be imposed on the tax on such transferred, in the proportion indirectly owned by the seller, (a) are valued amount. Further, to the extent that any distribution received by a U.S. Holder in an amount equal to or higher than UTA 210,000 (approximately US$200 on its common shares exceeds 125% of the average of the annual distributions million) (adjusted by the Chilean inflation unit of reference) or (b) represent on the shares received during the preceding three years or the U.S. Holder’s 20% or more of the market value of the interest held by such seller in such holding period, whichever is shorter, that distribution would be subject to offshore holding company. taxation in the same manner as gain, as described immediately above. Certain 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 alternative are met. This rate might be subject to change in the short GeoPark 145 term. See “Item 4. Information on the Company—B. Business overview— shares—The transfer of our common shares may be subject to capital gains Industry and regulatory framework —Chile.” taxes pursuant to indirect transfer rules in Chile.” As of December 31, 2017, our Chilean Assets represented more than UTA F. Dividends and paying agents 210,000 and represent more than 38% of our total assets. Not applicable. The 35% rate is calculated pursuant to one of the following methods, as determined by the seller: G. Statement by experts • the sale price of the shares minus the acquisition cost of such shares, Not applicable. multiplied by the percentage or proportion of the part of the underlying Chilean Assets’ fair market value (which assets are deemed to be “indirectly transferred” H. Documents on display by virtue of the sale of shares) to the fair market value of the shares of the seller; We are subject to the informational requirements of the Exchange Act. or Accordingly, we are required to file reports and other information with the • the portion of the sales price of the shares equal to the proportion SEC, including annual reports on Form 20-F and reports on Form 6-K. You may of the fair market value of the underlying Chilean Assets, minus the inspect and copy reports and other information filed with the SEC at the Public corresponding proportion in the tax cost of such Chilean Assets for the Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on corresponding holding entity. the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website However, the seller may opt to be taxed as if the underlying Chilean Assets that contains reports and other information about issuers, like us, that file had been sold directly in which case a different set of tax rules may apply. electronically with the SEC. The address of that website is www.sec.gov. The tax is payable by the seller of the shares; however, the buyer shall make a provisional withholding unless the seller declares and pays the tax within the I. Subsidiary information month following the sale, payment, remittance or it is credited into its account Not applicable. or is put at its disposal. Also, if the seller fails to declare and pay this tax, and the buyer has not complied with its withholding obligations, the Chilean tax ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT authority (Servicio de Impuestos Internos) may charge such tax directly to any MARKET RISK of them. In addition, the Chilean tax authority may require us, the seller, the buyer, or its representative in Chile, to file an affidavit with the information We are exposed to a variety of market risks, including commodity price risk, necessary to assess this tax. interest rate risk, currency risk and credit (counterparty and customer) risk. Based on information available to us, (i) no Chilean resident holds 5% or The term “market risk” refers to the risk of loss arising from adverse changes in more of our rights to equity, control or profits; or (ii) residents in black-listed interest rates, oil and natural gas prices and foreign currency exchange rates. jurisdictions hold 50% or more of our rights to equity, control or profits. For further information on our market risks, please see Note 3 to our Therefore, we do not believe the indirect transfer rules will apply to transfers Consolidated Financial Statements. 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 ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES (considering dispositions by related persons and over the preceding 12-month period). A. Debt securities Not applicable. However, there can be no assurance that, at any time in the future, a Chilean resident will not hold 5% or more of our rights to equity, control or profits or B. Warrants and rights that residents in black-listed jurisdictions will not hold 50% or more of our Not applicable. rights to equity, control or profits. If this were to occur, all sales of our common shares would be subject to the indirect transfer tax referred to above. C. Other securities Our expectations regarding the indirect transfer rules are based on our Not applicable. understandings, analysis and interpretation of these enacted indirect transfer rules, which are subject to additional interpretation and rule-making by the D. American Depositary Shares Chilean authorities. As such, there is uncertainty relating to the application by Not applicable. Chilean authorities of the indirect transfer rules on us. See “Item 3. Key Information—D. Risk Factors—Risks related to our common 146 GeoPark 20-F PART II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES • provide reasonable assurance that transactions are recorded as necessary to A. Defaults No matters to report. B. Arrears and delinquencies No matters to report. permit preparation of financial statements, in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorization of our management and directors; and • provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. 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, 2017, 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, 2017, 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, 2017, 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, Not applicable. processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (2) accumulated and communicated to our D. Changes in Internal Control over Financial Reporting management to allow timely decisions regarding required disclosures. There have been no changes in our internal control over financial reporting during the period covered by this annual report on Form 20-F that have B. Management’s Annual Report on Internal Control over Financial materially affected or reasonably likely to materially affect our internal control Reporting over financial reporting. Our management is responsible for establishing and maintaining an adequate internal control over financial reporting as defined in Rule ITEM 16. RESERVED 13a-15(f ) under the Exchange Act. Our internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial We have determined that Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield officers, management and other personnel, to provide reasonable assurance are independent, as such term is defined under SEC rules applicable to foreign regarding the reliability of financial reporting and the preparation of our private issuers. In addition, Mr. Robert Bedingfield and Mr. Juan Cristobal Pavez financial statements for external reporting purposes, in accordance with are regarded as audit committee financial experts. ITEM 16A. Audit committee financial expert generally accepted accounting principles. These include those policies and procedures that: ITEM 16B. Code of Conduct • pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; We have adopted a code of conduct applicable to the board of directors and GeoPark 147 all employees. Since its effective date on September 24, 2012, we have not 16C have been approved by the Audit Committee. waived compliance with or amended the code of conduct. ITEM 16C. Principal Accountant Fees and Services ITEM 16D. Exemptions from the listing standards for audit committees Amounts billed by PwC for audit and other services were as follows: None. Audit fees Audit related fees Tax services fees Other fees paid Total Audit Fees ITEM 16E. Purchases of equity securities by the issuer and affiliated 2017 2016 purchasers (in millions of US$) 0.73 0.14 0.21 0.03 1.11 0.49 During 2017, no purchases of our common shares were made by or on behalf of — us or by any affiliated purchaser. 0.13 — ITEM 16F. Change in registrant’s certifying accountant 0.62 Not applicable. Audit fees are fees billed for professional services rendered by the principal ITEM 16G. Corporate governance accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with Our common shares are listed on the NYSE. We are therefore required to statutory and regulatory filings or engagements for those fiscal years. It includes comply with certain of the NYSE’s corporate governance listing standards the audit of our Consolidated Financial Statements and other services that (the “NYSE Standards”). As a foreign private issuer, we may follow our generally only the independent accountant reasonably can provide, such as home country’s corporate governance practices in lieu of most of the comfort letters, statutory audits, consents and assistance with and review of NYSE Standards. Our corporate governance practices differ in certain documents filed with the SEC. Audit-Related Fees significant respects from those that U.S. companies must adopt in order to maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed Company Manual, a brief, general summary of those differences is Audit-related fees are fees billed for assurance and related services that are provided as follows. reasonably related to the performance of the audit or review of our Consolidated Financial Statements and not reported under the previous category. These Director independence services would include, among others: accounting consultations and audits The NYSE Standards require a majority of the membership of NYSE-listed in connection with acquisitions, internal control reviews, attest services that company boards to be composed of independent directors. Neither are not required by statue or regulation and consultation concerning financial Bermuda law, the law of our country of incorporation, nor our memorandum accounting and reporting standards. Tax Fees of association or bye-laws require a majority of our board to consist of independent directors. Tax fees are fees billed for professional services for tax compliance, tax advice Non-management directors’ executive sessions and tax planning. The NYSE Standards require non-management directors of NYSE-listed companies to meet at regularly scheduled executive sessions without Pre-Approval Policies and Procedures management. Our memorandum of association and bye-laws do not require Following the listing of our common shares on the NYSE, the Audit our non-management directors to hold such meetings. Committee proposes the appointment of the independent auditor to the Board to be put to shareholders for approval at the Annual General meeting. The committee oversees the auditor selection process for new auditors Committee member composition The NYSE Standards require domestic NYSE-listed domestic companies to and ensures key partners in the appointed firm are rotated in accordance have a nominating/corporate governance committee and a compensation with best practices. Also, following our NYSE listing, the Audit Committee committee that are composed entirely of independent directors. Bermuda law, is required to pre-approve the audit and non-audit fees and services the law of our country of incorporation, does not impose similar requirements. performed by the Company’s auditors in order to be sure that the provision of such services does not impair the audit firm’s independence. Independence of the compensation committee and its advisers All of the audit fees, audit-related fees and tax fees described in this item On January 11, 2013, the SEC approved NYSE listing standards that require 148 GeoPark 20-F 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 purposes and responsibilities or performance evaluations in a manner that would satisfy the NYSE’s requirements; acquire shareholder approval of equity compensation plans in certain cases; or adopt and make publicly available corporate governance guidelines. GeoPark 149 PART III ITEM 17. Financial statements No. Description We have responded to Item 18 in lieu of this item. among the International Finance Corporation, GeoPark Holdings ITEM 18. Financial statements Limited, Gerald O’Shaughnessy and James F. Park (incorporated herein by reference to Exhibit 10.4 to the Company’s Registration Statement Financial Statements are filed as part of this annual report, see pages 156 to on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 205 to this annual report. 2013). ITEM 19. Exhibits No. Description 4.5 Shareholders’ Agreement, dated May 20, 2011, among LG International Corporation, GeoPark Chile Limited Agencia en Chile and GeoPark Chile S.A. (incorporated herein by reference to Exhibit 10.7 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) 1.1 Certificate of Incorporation (incorporated herein by reference to Exhibit filed with the SEC on September 9, 2013). 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333- 4.6 Shareholders’ Agreement, dated December 18, 2012, among LG 191068) filed with the SEC on September 9, 2013). International Corporation, GeoPark Chile Limited Agencia en Chile and 1.2 Memorandum of Association (incorporated herein by reference to GeoPark Colombia S.A. (incorporated herein by reference to Exhibit 10.9 Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File to the Company’s Registration Statement on Form F-1 (File No. 333- No. 333-191068) filed with the SEC on September 9, 2013). 191068) filed with the SEC on September 9, 2013). 1.3 Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the 4.7 Subscription Agreement, dated October 18, 2011, among LG Company’s Registration Statement on Form F-1 (File No. 333-191068) International Corporation and GeoPark TdF S.A. (incorporated herein filed with the SEC on September 9, 2013). by reference to Exhibit 10.11 to the Company’s Registration Statement 1.4 Form of amended and restated bye-laws (incorporated herein by on Form F-1 (File No. 333-191068) filed with the SEC on September 9, reference to Exhibit 3.4 to the Company’s Registration Statement on 2013). Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 4.8 Shareholders’ Agreement, dated October 4, 2011, among LG 2.2 Indenture, dated September 21, 2017, among GeoPark Limited, the International Corporation, GeoPark TdF S.A. and GeoPark Chile S.A. Bank of New York Mellon and Lord Securities Corporation.* (incorporated herein by reference to Exhibit 10.12 to the Company’s 2.3 Contract of Pledge without Conveyance on Shares between GeoPark Registration Statement on Form F-1 (File No. 333-191068) filed with the Latin America Limited Agencia en Chile and Lord Securities Corporation, SEC on September 9, 2013). dated September 21, 2017.* 4.9 Purchase and Sale Agreement for Natural Gas between GeoPark Chile 2.4 Deed of Pledge of Membership Interest among GeoPark Latin America Limited Agencia en Chile and Methanex Chile SpA. (incorporated herein Coöperatie U.A., Stichting Collateral Agent Geopark and GeoPark Colombia by reference to Exhibit 10.15 to the Company’s Registration Statement Coöperatie U.A.* on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 4.1 Special Contract for the Exploration and Exploitation of 2013). † Hydrocarbons, Fell Block, dated April 29, 1997, among the Republic 4.10 First Addendum and Amendment to Purchase and Sale Agreement of Chile, the Chilean Empresa Nacional de Petróleo (ENAP) and for Natural Gas between GeoPark Chile Limited Agencia en Chile and Cordex Petroleums Inc. (incorporated herein by reference to Exhibit Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.16 10.1 to the Company’s Registration Statement on Form F-1 (File No. to the Company’s Registration Statement on Form F-1/A (File No. 333- 333-191068) filed with the SEC on September 9, 2013). 191068) filed with the SEC on October 10, 2013). † 4.2 Exploration and Production Contract regarding exploration for and 4.11 Second Addendum and Amendment to Purchase and Sale Agreement exploitation of hydrocarbons in the La Cuerva Block, dated April 16, for Natural Gas between GeoPark Chile Limited Agencia en Chile and 2008, between the Colombian Agencia Nacional de Hidrocarburos and Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.7 Hupecol Caracara LLC (incorporated herein by reference to Exhibit 10.2 to the Company’s Registration Statement on Form F-1/A (File No. 333- to the Company’s Registration Statement on Form F-1 (File No. 333- 191068) filed with the SEC on September 26, 2013). 191068) filed with the SEC on September 9, 2013). 4.12 Third Addendum and Amendment to Purchase and Sale Agreement 4.3 Exploration and Production Contract regarding exploration for and for Natural Gas between GeoPark Chile Limited Agencia en Chile and exploitation of hydrocarbons in the Llanos 34 Block, dated March 13, Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.18 2009, between the Colombian Agencia Nacional de Hidrocarburos and to the Company’s Registration Statement on Form F-1/A (File No. 333- Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit 191068) filed with the SEC on October 10, 2013). † 10.3 to the Company’s Registration Statement on Form F-1 (File No. 4.13 Fourth Addendum and Amendment to Purchase and Sale Agreement 333-191068) filed with the SEC on September 9, 2013). for Natural Gas between GeoPark Chile Limited Agencia en Chile and 4.4 Subscription and Shareholders Agreement, dated February 7, 2006, Methanex Chile SpA. (incorporated herein by reference to Exhibit 10.19 150 GeoPark 20-F No. Description No. Description to the Company’s Registration Statement on Form F-1/A (File No. 333- 4.23 Asset Purchase Agreement between GeoPark Argentina Ltd. and 191068) filed with the SEC on October 10, 2013). † Pluspetrol S.A., dated December 18, 2017.* 4.14 Fifth Addendum and Amendment to Purchase and Sale Agreement 4.24 Purchase and Sale Agreement for Crude Oil and Condensate of Fell Block for Natural Gas between GeoPark Chile Limited Agencia en Chile and between Empresa Nacional del Petróleo (ENAP) and GeoPark Fell S.p.A., Methanex Chile SpA. dated April 1, 2014. (incorporated herein by dated April 21, 2017.* reference to Exhibit 4.23 to the Company’s Annual Report on Form 20-F 8.21 Subsidiaries of GeoPark Limited.* filed with the SEC on April 30, 2015). † 12.1 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* 4.15 Sixth Addendum and Amendment to Purchase and Sale Agreement 12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* for Natural Gas between GeoPark Chile Limited Agencia en Chile 13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to and Methanex Chile SpA. dated May 1, 2015 (incorporated herein by section 906 of the Sarbanes-Oxley Act of 2002.* reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F 13.2 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to filed with the SEC on April 15, 2016). † section 906 of the Sarbanes-Oxley Act of 2002.* 4.16 Seventh Addendum and Amendment to Purchase and Sale Agreement 15.1 Consent of Price Waterhouse & Co. S.R.L., Argentina.* for Natural Gas between GeoPark Chile Limited Agencia en Chile and 15.2 Consents of DeGolyer and MacNaughton to use its report.* Methanex Chile SpA. dated April 1, 2016 (incorporated herein by 99.1 Reserves Report of DeGolyer and MacNaughton dated February 15, reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F 2018, for reserves in Chile, Colombia, Peru, Brazil as of December 31, filed with the SEC on April 11, 2017). † 2017.* 4.17 Contract for the sale and Purchase of Natural Gas 2017-2027 between GeoPark Fell SpA and Methanex Chile SpA dated March 31, 2017 (incorporated herein by reference to Exhibit 4.22 to the Company’s * † Filed with this Annual Report on Form 20-F. Confidential treatment of certain provisions of these exhibits has Annual Report on Form 20-F filed with the SEC on April 11, 2017). † been requested with the SEC. Omitted material for which confidential 4.18 Members’ Agreement, dated January 8, 2014, among GeoPark Latin treatment has been requested has been filed separately with the SEC. America Coöperatie U.A., GeoPark Colombia Coöperatie U.A. and LG International Corporation (incorporated herein by reference to Exhibit 10.20 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on January 21, 2014). 4.19 Prepayment Agreement for an Amount of up to US$100,000,000, dated December 18, 2015, among C.I. Trafigura Petroleum Colombia 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). 4.20 Amendment Agreement No. 1 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated September 1, 2016 relating to the Prepayment Agreement dated December 18, 2015 (incorporated herein by reference to Exhibit 4.27 to the Company’s Annual Report on Form 20-F filed with the SEC on April 11, 2017). 4.21 Amendment Agreement No. 2 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated December 16, 2016 relating to the Prepayment Agreement dated December 18, 2015 (incorporated herein by reference to Exhibit 4.28 to the Company’s Annual Report on Form 20-F filed with the SEC on April 11, 2017). 4.22 Amendment Agreement No. 3 among GeoPark Colombia SAS, C.I. Trafigura Petroleum Colombia SAS and GeoPark Ltd. dated February 13, 2017 relating to the Prepayment Agreement dated December 18, 2015 (incorporated herein by reference to Exhibit 4.29 to the Company’s Annual Report on Form 20-F filed with the SEC on April 11, 2017). GeoPark 151 Glossary of Oil and Natural Gas Terms The terms defined in this section are used throughout this annual report: that are separated vertically by intervening impervious strata, or laterally by “appraisal well” means a well drilled to further confirm and evaluate the local geologic barriers, or by both. Reservoirs that are associated by being presence of hydrocarbons in a reservoir that has been discovered. in overlapping or adjacent fields may be treated as a single or common “API” means the American Petroleum Institute’s inverted scale for denoting the operational field. The geological terms structural feature and stratigraphic “light” or “heaviness” of crude oils and other liquid hydrocarbons. condition are intended to identify localized geological features as opposed to “bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. in reference to crude oil, condensate or natural gas liquids. “formation” means a layer of rock which has distinct characteristics that differ “bcf” means one billion cubic feet of natural gas. from nearby rock. “bcm” means billion cubic meters. “mbbl” means one thousand barrels of crude oil, condensate or natural gas “boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being liquids. equivalent to one barrel of oil. “boepd” means barrels of oil equivalent per day. “bopd” means barrels of oil per day. “mboe” means one thousand barrels of oil equivalent. “mcf” means one thousand cubic feet of natural gas. “Measurements” include: “British thermal unit” or “btu” means the heat required to raise the temperature • “m” or “meter” means one meter, which equals approximately 3.28084 feet; of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. • “km” means one kilometer, which equals approximately 0.621371 miles; “basin” means a large natural depression on the earth’s surface in which • “sq. km” means one square kilometer, which equals approximately 247.1 sediments generally brought by water accumulate. acres; “CEOP” ( Contrato Especial de Operación ) means a special operating contract • “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent the Chilean signs with a company or a consortium of companies for the to approximately 0.15898 cubic meters; exploration and exploitation of hydrocarbon wells • “boe” means one barrel of oil equivalent, which equals approximately “completion” means the process of treating a drilled well followed by the 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of installation of permanent equipment for the production of natural gas or oil, or in natural gas to one barrel of oil; the case of a dry hole, the reporting of abandonment to the appropriate agency. • “cf” means one cubic foot; “developed acreage” means the number of acres that are allocated or • “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, assignable to productive wells or wells capable of production. respectively; “developed reserves” are expected quantities to be recovered from existing • “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, wells and facilities. Reserves are considered developed only after the necessary respectively; equipment has been installed or when the costs to do so are relatively minor • “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, compared to the cost of a well. Where required facilities become unavailable, it respectively; and may be necessary to reclassify developed reserves as 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 grouped on or related to the same individual geological structural feature oil nor natural gas will be present, at least not in commercial volumes. and/or stratigraphic condition. There may be two or more reservoirs in a field “proved developed reserves” means those proved reserves that can be 152 GeoPark 20-F 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. “stratigraphic test well” means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily 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, 2018 154 GeoPark 20-F GeoPark 155 Consolidated Financial Statements As of and for the year ended 31 December 2017 156 GeoPark 20-F 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 158 159 159 160 161 162 163 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, 2017 and 2016, 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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) Ezequiel Luis Mirazon Autonomous City of Buenos Aires, Argentina March 7, 2018 We have served as the Company’s auditor since 2009. 158 GeoPark 20-F Consolidated Statement of Income Amounts in US$ ´000 Note 2017 2016 2015 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 (recognised) 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) benefit LOSS FOR THE YEAR Attributable to: Owners of the Company Non-controlling interest Losses per share (in US$) for loss attributable to owners of the Company. Basic Losses per share (in US$) for loss attributable to owners of the Company. Diluted Consolidated Statement of Comprehensive Income Amounts in US$ ´000 Loss for the year Other comprehensive income: Items that may be subsequently reclassified to profit or loss Currency translation difference Total comprehensive loss for the year Attributable to: Owners of the Company Non-controlling interest The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements. 7 8 9 12 13 14 20 330,122 (15,448) (98,987) (7,694) (42,054) (1,136) (74,885) (5,834) 192,670 (2,554) (67,235) (10,282) (34,170) (4,222) (75,774) (31,366) 209,690 - (86,742) (13,831) (37,471) (5,211) (105,557) (30,084) 20-36 - 5,664 (149,574) (5,088) 78,996 (1,344) (13,711) (28,613) (232,491) 15 15 15 (53,511) (36,229) (36,924) 2,016 (2,193) 25,308 2,128 13,872 1,269 (33,474) (48,842) (301,620) 17 (43,145) (11,804) 17,054 (17,837) (60,646) (284,566) (24,228) 6,391 (49,092) (11,554) (234,031) (50,535) 19 19 (0.40) (0.82) (4.05) (0.40) (0.82) (4.05) 2017 2016 2015 (17,837) (60,646) (284,566) (512) 7,102 (1,001) (18,349) (53,544) (285,567) (24,740) 6,391 (41,990) (11,554) (235,032) (50,535) 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 Other financial assets Cash and cash equivalents 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 TOTAL CURRENT LIABILITIES TOTAL LIABILITIES TOTAL EQUITY AND LIABILITIES The Consolidated Financial Statements were approved by the Board of Directors on 7 March 2018. The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements. 160 GeoPark 20-F Note 2017 2016 20 22 25 18 24 23 24 24 22 25 25 26 27 28 18 29 27 25 29 517,403 473,646 3,823 22,110 27,636 235 2,852 19,547 23,053 241 571,207 519,339 5,738 19,519 7,518 26,048 21,378 134,755 214,956 786,163 3,515 18,426 7,402 15,815 2,480 73,563 121,201 640,540 61 239,191 129,606 60 236,046 130,118 (283,933) (260,459) 84,925 41,915 105,765 35,828 126,840 141,593 418,540 319,389 46,284 2,286 25,921 42,509 2,770 34,766 493,031 399,434 7,664 19,289 42,942 96,397 166,292 659,323 786,163 39,283 3,067 5,155 52,008 99,513 498,947 640,540 Consolidated Statement of Changes in Equity Amount in US$ ‘000 Equity at 1 January 2015 Comprehensive income: Loss for the year Currency translation differences Total Comprehensive Income for the Year 2015 Transactions with owners: Share-based payment (Note 30) Repurchase of shares (Note 26) Total 2015 Balances at 31 December 2015 Comprehensive income: Loss for the year Currency translation differences Total Comprehensive 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 for the year Currency translation differences Total Comprehensive Loss 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 Attributable to owners of the Company (Accumulated Losses) Non- Share Share Other Translation Retained controlling Capital Premium Reserve Reserve Earnings 58 210,886 127,527 (3,510) 40,596 Interest 103,569 Total 479,126 - - - 1 - 1 - - - 22,734 (1,615) 21,119 - - - - - - - (234,031) (50,535) (284,566) (1,001) - - (1,001) (1,001) (234,031) (50,535) (285,567) - - - (14,993) - (14,993) 481 - 481 8,223 (1,615) 6,608 59 232,005 127,527 (4,511) (208,428) 53,515 200,167 - - - 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 The notes on pages 163 to 205 are an integral part of these Consolidated Financial Statements. GeoPark 161 Consolidated Statement of Cash Flow Amounts in US$ ‘000 Note 2017 2016 2015 Cash flows from operating activities Loss for the year Adjustments for: Income tax expense (benefit) Depreciation Loss on disposal of property, plant and equipment Impairment loss (reversed) recognised for non-financial assets Write-off of unsuccessful exploration efforts Accrual of borrowing’s interests Borrowings cancellation costs Amortisation of other long-term liabilities Unwinding of long-term liabilities Accrual of share-based payment Foreign exchange loss (gain) Unrealized 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 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 Cash flows from / (used in) / from financing activities - net Net increase (decrease) 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 163 to 205 are an integral part of these Consolidated Financial Statements. 162 GeoPark 20-F (17,837) (60,646) (284,566) 17 20-36 20 15 28 28 8 5 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 (17,054) 105,557 2,000 149,574 30,084 28,460 - (703) 2,575 8,223 (13,872) 33,474 3,068 (1,956) 11,920 82,884 - (7,625) (24,104) 25,895 (105,604) (39,306) (48,842) (105,604) (39,306) (48,842) 425,000 (6,683) 1,155 - (355,022) (27,688) (12,315) 186 - 5,210 (1,991) (22,645) (25,490) - (479) (6,406) 7,036 - 2,400 (1,615) (89) (25,754) - - 23,968 (51,136) (18,022) 60,522 73,563 670 134,755 (7,558) (40,969) 82,730 (1,609) 73,563 127,672 (3,973) 82,730 134,734 73,551 82,720 21 12 10 134,755 73,563 82,730 Notes to the Consolidated Financial Statements Note 1 General Information The adoption of these amendments did not have any impact on the current GeoPark Limited (the “Company”) is a company incorporated under the law period or any prior period and is not likely to affect future periods. of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM11, Bermuda. New standards, amendments and interpretations issued but not effective for the The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and production for oil and gas • IFRS 2 Share based payments: amended in June 2016 to clarify the reserves in Chile, Colombia, Brazil, Peru and Argentina. measurement basis for cash-settled share-based payments and the financial year beginning 1 January 2017 and not early adopted. accounting for modifications that change an award from cash-settled to These Consolidated Financial Statements were authorised for issue by the equity-settled. It also introduces an exception to IFRS 2 principles by requiring Board of Directors on 7 March 2018. Note 2 an award to be treated as if it was wholly equity-settled, where an employer is obliged to withhold an amount for the employee’s tax obligation associated with a share-based payment and pay that amount to the tax authority. It is effective for annual periods beginning on or after January 1, 2018. The Group Summary of significant accounting policies estimates that these amendments will not have a material impact on the The principal accounting policies applied in the preparation of these Group’s operating results or financial position. Consolidated Financial Statements are set out below. These policies have been consistently applied to the years presented, unless otherwise stated. • IFRS 9 Financial Instruments and associated amendments to various other 2.1 Basis of preparation standards: IFRS 9 replaces the multiple classification and measurement models in IAS 39. Classification of debt assets will be driven by the entity’s The Consolidated Financial Statements of GeoPark Limited have been business model for managing the financial assets and the contractual cash prepared in accordance with International Financial Reporting Standards flow characteristics of the financial assets. A debt instrument is measured (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), at amortised cost if: a) the objective of the business model is to hold the under the historical cost convention. financial asset for the collection of the contractual cash flows, and b) the contractual cash flows under the instrument solely represent payments The Consolidated Financial Statements are presented in thousands of United of principal and interest. All other debt and equity instruments, including States Dollars (US$’000) and all values are rounded to the nearest thousand investments in complex debt instruments and equity investments, must be (US$’000), except in the footnotes and where otherwise indicated. recognised at fair value. The preparation of financial statements in conformity with IFRS requires the All fair value movements on financial assets are taken through the statement use of certain critical accounting estimates. It also requires management to of profit or loss, except for equity investments that are not held for trading, exercise its judgement in the process of applying the Group’s accounting which may be recorded in the statement of profit or loss or in reserves policies. The areas involving a higher degree of judgement or complexity, or (without subsequent recycling to profit or loss). For financial liabilities that are areas where assumptions and estimates are significant to the Consolidated measured under the fair value option entities will need to recognise the part Financial Statements are disclosed in this note under the title “Accounting of the fair value change that is due to changes in their own credit risk in other estimates and assumptions”. comprehensive income rather than profit or loss. All the information included in these Consolidated Financial Statements The new hedge accounting rules (released in December 2013) align hedge corresponds to the Group, except where otherwise indicated. accounting more closely with common risk management practices. As a 2.1.1 Changes in accounting policy and disclosure New and amended standards adopted by the Group general rule, it will be easier to apply hedge accounting going forward. The new impairment model under IFRS 9 requires the recognition of impairment provisions based on expected credit losses rather than only The following standards have been adopted by the Group for the first time for incurred credit losses as is the case under IAS 39. It applies to financial assets the financial year beginning on or after 1 January 2017: classified at amortised cost, debt instruments measured at fair value through other comprehensive income, contract assets under IFRS 15, lease receivables, • Recognition of Deferred Tax Assets for Unrealised Losses – Amendments to loan commitments and certain financial guarantee contracts. IAS 12 • Disclosure initiative – Amendments to IAS 7 GeoPark 163 The new standard also introduces expanded disclosure requirements and • IFRIC 22 Foreign Currency Transactions and Advance Consideration: changes in presentation. issued in December 2016. The interpretation addresses how to determine the date of the transaction for the purpose of determining the exchange Management has assessed the effects of applying the new standard on the rate to use on initial recognition of the related asset, expense or income Group’s Consolidated Financial Statements and concluded that no material related to an entity that has received or paid an advance consideration impact will be expected. in a foreign currency. The date of the transaction is the date on which an entity initially recognises the non-monetary asset or non-monetary liability • IFRS 15 Revenue from contracts with customers and associated arising from the payment or receipt of advance consideration. It is effective amendments to various other standards: The IASB has issued a new standard for annual periods beginning on January 1, 2018. The Group estimates for the recognition of revenue. This will replace IAS 18 which covers contracts that these interpretations will not have a material impact on the Group’s for goods and services and IAS 11 which covers construction contracts. The operating results or financial position. new standard is based on the principle that revenue is recognised when control of a good or service transfers to a customer so the notion of control • Sale or contribution of assets between an investor and its associate or replaces the existing notion of risks and rewards. joint venture – Amendments to IFRS 10 and IAS 28: The amendments clarify These accounting changes may have flow-on effects on the entity’s business investor and its associates or joint ventures. practices regarding systems, processes and controls, compensation and bonus plans, contracts, tax planning and investor communications. Entities will have • Improvements to IFRSs – 2014-2016 Cycle: amendments issued in a choice of full retrospective application, or prospective application with December 2016 that are effective for periods beginning on or after January the accounting treatment for sales or contribution of assets between an additional disclosures. 1, 2018. The Group estimates that these amendments will not have an impact on the Group’s operating results or financial position. It is mandatory for financial years commencing on or after 1 January 2018. The Group intends to adopt the standard using the modified retrospective There are no other standards that are not yet effective and that would be approach which means that the cumulative impact of the adoption will be expected to have a material impact on the entity in the current or future recognised in retained earnings as of 1 January 2018 and that comparatives reporting periods and on foreseeable future transactions. will not be restated. 2.2 Going concern Management has assessed the effects of applying the new standard on the The Directors regularly monitor the Group’s cash position and liquidity risks Group’s Consolidated Financial Statements and concluded that no material throughout the year to ensure that it has sufficient funds to meet forecast impact will be expected. operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors • IFRS 16 Leases: will affect primarily the accounting by lessees and will result to enable the Group to manage the risk of any funding short falls and/or in the recognition of almost all leases on balance sheet. The standard removes potential debt covenant breaches. the current distinction between operating and financing leases and requires recognition of an asset (the right to use the leased item) and a financial Considering macroeconomic environment conditions, the performance liability to pay rentals for virtually all lease contracts. An optional exemption of the operations, the US$ 425,000,000 debt fund raising completed in exists for short-term and low-value leases. The accounting by lessors will September 2017, the Group’s cash position, and the fact that over 99% of its not significantly change. Some differences may arise as a result of the new total indebtedness maturing in 2024, the Directors have formed a judgement, guidance on the definition of a lease. at the time of approving the financial statements, that there is a reasonable expectation that the Group has adequate resources to meet all its obligations The Group has not yet determined to what extent its commitments will result for the foreseeable future. For this reason, the Directors have continued in the recognition of an asset and a liability for future payments and how to adopt the going concern basis in preparing the Consolidated Financial this will affect the Group’s profit and classification of cash flows. Some of the Statements. commitments may be covered by the exception for short-term and low-value leases and some commitments may relate to arrangements that will not 2.3 Consolidation qualify as leases under IFRS 16. At this stage, the Group does not intend to Subsidiaries are all entities (including structured entities) over which the group adopt the standard before its effective date. The Group intends to apply the has control. The Group controls an entity when the Group is exposed to, or simplified transition approach and will not restate comparative amounts for has rights to, variable returns from its involvement with the entity and has the the year prior to first adoption. ability to affect those returns through its power over the entity. Subsidiaries 164 GeoPark 20-F are fully consolidated from the date on which control is transferred to the the US Dollar, meanwhile for the Group´s Brazilian company the functional Group. They are deconsolidated from the date that control ceases. currency is the local currency, which is the Brazilian Real. The Group applies the acquisition method to account for business b) Transactions and balances combinations. The consideration transferred for the acquisition of a subsidiary Foreign currency transactions are translated into the functional currency is the fair value of the assets transferred, the liabilities incurred by the former using the exchange rates prevailing at the dates of the transactions. Foreign owners of the acquiree and the equity interests issued by the Group. The exchange gains and losses resulting from the settlement of such transactions consideration transferred includes the fair value of any asset or liability and from the translation at period end exchange rates of monetary assets resulting from a contingent consideration arrangement. Identifiable assets and liabilities denominated in foreign currencies are recognised in the acquired and liabilities and contingent liabilities assumed in a business Consolidated Statement of Income. combination are measured initially at their fair values at the acquisition date. Acquisition-related costs are expensed as incurred. 2.6 Joint arrangements The excess of the consideration transferred, the amount of any non- joint operations or joint ventures depending on the contractual rights and Under IFRS 11 investments in joint arrangements are classified as either controlling interest in the acquired entity, and the acquisition-date fair obligations of each investor. value of any previous equity interest in the acquired entity over the fair value of the identifiable net assets acquired is recorded as goodwill. If the The Group has assessed the nature of its joint arrangements and determined total of consideration transferred, non-controlling interest recognised and them to be joint operations. The Group combines its share in the joint previously held interest measured is less than the fair value of the net assets operations individual assets, liabilities, results and cash flows on a line-by-line of the subsidiary acquired in the case of a bargain purchase, the difference is basis with similar items in its financial statements. recognised directly in the income statement. 2.7 Revenue recognition Intercompany transactions, balances and unrealised gains on transactions Revenue from the sale of crude oil and gas is recognised in the between the Group and its subsidiaries are eliminated. Unrealised losses are Consolidated Statement of Income when risk is transferred to the also eliminated unless the transaction provides evidence of an impairment purchaser, and if the revenue can be measured reliably and is expected of the asset transferred. Amounts reported in the financial statements of to be received. Revenue is shown net of VAT, discounts related to the sale subsidiaries have been adjusted where necessary to ensure consistency with and overriding royalties due to the ex-owners of oil and gas properties the accounting policies adopted by the Group. where the royalty arrangements represent a retained working interest in the property. See Note 32 (a). 2.4 Segment reporting Operating segments are reported in a manner consistent with the internal 2.8 Production and operating costs reporting provided to the chief operating decision-maker. The chief operating Production costs include wages and salaries incurred to achieve the revenue decision-maker, who is responsible for allocating resources and assessing for the year. Direct and indirect costs of raw materials and consumables, performance of the operating segments, has been identified as the Executive rentals, leasing and royalties are also included within this account. Committee. This committee is integrated by the CEO, COO, CFO and managers in charge of the Geoscience, Operations, Corporate Governance, Finance and 2.9 Financial results People departments. This committee reviews the Group’s internal reporting Financial results include interest expenses, interest income, bank charges, the in order to assess performance and allocate resources. Management has amortisation of financial assets and liabilities, and foreign exchanges gain determined the operating segments based on these reports. and losses. The Group has capitalised borrowing cost for wells and facilities 2.5 Foreign currency translation a) Functional and presentation currency that were initiated after 1 January 2009. The capitalisation rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s general borrowings during the The Consolidated Financial Statements are presented in US Dollars, which is year, which was 6.90% at year end 2017 (7.98% at year end 2016 and 2015). the Group’s presentation currency. Amounts capitalised during the year amounted to US$ 610,841 (US$ 254,950 Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in 2.10 Property, plant and equipment in 2016 and US$ 637,390 in 2015). which the entity operates (the “functional currency”). The functional currency Property, plant and equipment are stated at historical cost less depreciation of Group companies incorporated in Chile, Colombia, Peru and Argentina is and impairment charge, if applicable. Historical cost includes expenditure that GeoPark 165 is directly attributable to the acquisition of the items; including provisions for furniture and vehicles) not directly associated with oil and gas activities has asset retirement obligation. been calculated by means of the straight line method by applying such annual rates as required to write-off their value at the end of their estimated useful Oil and gas exploration and production activities are accounted for in lives. The useful lives range between 3 years and 10 years. accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with Depreciation is allocated in the Consolidated Statement of Income as a IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalising separate line to better follow up the performance of the business. exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Costs incurred prior An asset’s carrying amount is written down immediately to its recoverable to obtaining legal rights to explore are expensed immediately to the amount if the asset’s carrying amount is greater than its estimated recoverable Consolidated Statement of Income. amount (see Impairment of non-financial assets in Note 2.12). Exploration and evaluation costs may include: license acquisition, geological 2.11 Provisions and other long-term liabilities and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of Provisions for asset retirement obligations, deferred income, restructuring exploratory wells. No depreciation and/or amortisation are charged during obligations and legal claims are recognised when the Group has a present the exploration and evaluation phase. Upon completion of the evaluation legal or constructive obligation as a result of past events; it is probable that phase, the prospects are either transferred to oil and gas properties or charged an outflow of resources will be required to settle the obligation; and the to expense (exploration costs) in the period in which the determination is amount has been reliably estimated. Restructuring provisions comprise lease made depending whether they have found reserves or not. If not developed, termination penalties and employee termination payments. exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is Provisions are measured at the present value of the expenditures expected to 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 A charge of US$ 5,834,000 has been recognised in the Consolidated Statement the obligation. The increase in the provision due to the passage of time is of Income within Write-off of unsuccessful exploration efforts (US$ 31,366,000 recognised as financial expense. in 2016 and US$ 30,084,000 in 2015). See Note 20. 2.11.1 Asset Retirement Obligation All field development costs are considered construction in progress until they The Group records the fair value of the liability for asset retirement obligations are finished and capitalised within oil and gas properties, and are subject to in the period in which the wells are drilled. When the liability is initially depreciation once completed. Such costs may include the acquisition and recorded, the Group capitalises the cost by increasing the carrying amount of installation of production facilities, development drilling costs (including dry the related long-lived asset. Over time, the liability is accreted to its present holes, service wells and seismic surveys for development purposes), project- value at each reporting period, and the capitalised cost is depreciated over related engineering and the acquisition costs of rights and concessions related the estimated useful life of the related asset. According to interpretations to proved properties. and application of current legislation and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect Workovers of wells made to develop reserves and/or increase production the environment, the Group has considered it appropriate to periodically are capitalised 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 Capitalised 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 recognised in the Consolidated estimates are recognised 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 addition in 2016 and the amounts used in 2017 the Consolidated Statement of Income simultaneously with the amortisation 166 GeoPark 20-F correspond to the deferred income related to the take or pay provision first-out (FIFO) method. associated to gas sales in Brazil. 2.15 Current and deferred income tax 2.12 Impairment of non-financial assets The tax expense for the year comprises current and deferred tax. Tax is Assets that are not subject to depreciation and/or amortisation (i.e.: recognised in the Consolidated Statement of Income. exploration and evaluation assets) are tested annually for impairment. Assets that are subject to depreciation and/or amortisation are reviewed for The current income tax charge is calculated on the basis of the tax laws impairment whenever events or changes in circumstances indicate that the enacted or substantially enacted at the balance sheet date in the countries carrying amount may not be recoverable. where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of An impairment loss is recognised for the amount by which the asset’s carrying applicable tax laws and regulations in many jurisdictions. The resolution of amount exceeds its recoverable amount. The recoverable amount is the higher tax positions taken by the Group, through negotiations with relevant tax of an asset’s fair value less costs to sell and value in use. For the purposes authorities or through litigation, can take several years to complete and in of assessing impairment, assets are grouped at the lowest levels for which some cases it is difficult to predict the ultimate outcome. there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered Deferred income tax is recognised, using the liability method, on temporary impairment are reviewed for possible reversal of the impairment at each differences arising between the tax bases of assets and liabilities and their reporting date. carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or No asset should be kept as an exploration and evaluation asset for a period substantially enacted as of the balance sheet date and are expected to apply of more than three years, except if it can be clearly demonstrated that the when the related deferred income tax asset is realised or the deferred income carrying value of the investment will be recoverable. tax liability is settled. During 2017, no impairment loss was recognised (impairment loss reversed for In addition, the Group has tax-loss carry-forwards in certain taxing US$ 5,664,000 in 2016 and impairment loss recognised for US$ 149,574,000 in jurisdictions that are available to be offset against future taxable profit. 2015). See Note 36. The write-offs are detailed in Note 20. However, deferred tax assets are recognised only to the extent that it is 2.13 Lease contracts probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing All current lease contracts are considered to be operating leases on the basis whether this is the case. To the extent that actual outcomes differ from that the lessor retains substantially all the risks and rewards related to the management’s estimates, taxation charges or credits may arise in future ownership of the leased asset. Payments related to operating leases and other periods. rental agreements are recognised in the Consolidated Income Statement on a straight line basis over the term of the contract. The Group’s total Deferred income tax liabilities are provided on taxable temporary differences commitment relating to operating leases and rental agreements is disclosed arising from investments in subsidiaries and joint arrangements, except in Note 32. for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the 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 recognise an amount receivable equal to the not expect taxable profit. Hence deferred tax is recognised 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 recognise amounts to Crude oil is measured at the lower of cost and net realisable value. Materials approximately US$ 12,300,000. 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, GeoPark 167 2.16 Financial assets write-down is determined as the difference between the asset’s carrying Financial assets are divided into the following categories: loans and amount and the present value of estimated future cash flows. receivables; financial assets at fair value through profit or loss; available-for- sale financial assets; and held-to-maturity investments. Financial assets are 2.19 Cash and cash equivalents assigned to the different categories by management on initial recognition, Cash and cash equivalents includes cash in hand, deposits held at call with depending on the purpose for which the investments were acquired. The banks, other short-term highly liquid investments with original maturities designation of financial assets is re-evaluated at every reporting date at which of three months or less, and bank overdrafts. Bank overdrafts, if any, are a choice of classification or accounting treatment is available. shown within borrowings in the current liabilities section of the Consolidated All financial assets are recognised when the Group becomes a party to the contractual provisions of the instrument. 2.20 Trade and other payables Statement of Financial Position. All financial assets are initially recognised at fair value, plus transaction costs. acquired in the ordinary course of the business from suppliers. Accounts Derecognition of financial assets occurs when the rights to receive cash flows less (or in the normal operating cycle of the business if longer). If not, they are from the investments expire or are transferred and substantially all of the presented as non-current liabilities. risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date. Trade payables are recognised initially at fair value and subsequently payable are classified as current liabilities if payment is due within one year or Trade payables are obligations to pay for goods or services that have been measured at amortised cost using the effective interest method. Interest and other cash flows resulting from holding financial assets are recognised in the Consolidated Statement of Income when receivable, 2.21 Derivatives regardless of how the related carrying amount of financial assets is measured. Derivative financial instruments are recognised in the statement of financial Loans and receivables are non-derivative financial assets with fixed or through profit and loss. They are presented as current assets or liabilities if they are determinable payments that are not quoted in an active market. They are expected to be settled within 12 months after the end of the reporting period. position as assets or liabilities and initially and subsequently measured at fair value included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. The The market-to-market fair value of the Group’s outstanding derivative instruments Group’s loans and receivables comprise trade receivables, prepayments is based on independently provided market rates and determined using standard and other receivables and cash and cash equivalents in the balance sheet. valuation techniques, including the impact of counterparty credit risk and are They arise when the Group provides money, goods or services directly to a within level 2 of the fair value hierarchy. Gains and losses arising from changes debtor with no intention of trading the receivables. Loans and receivables are in fair value are recognised in the Consolidated Statement of Income within subsequently measured at amortised cost using the effective interest method, Commodity risk management contracts. less provision for impairment. Any change in their value through impairment or reversal of impairment is recognised in the Consolidated Statement of For more information about derivatives please refer to Note 8. Income. All of the Group’s financial assets are classified as loan and receivables. 2.22 Borrowings 2.17 Other financial assets Borrowings are obligations to pay cash and are recognised when the Group Non current other financial assets include contributions made for becomes a party to the contractual provisions of the instrument. environmental obligations according to a Colombian and Brazilian government request and are restricted for those purposes. Borrowings are recognised initially at fair value, net of transaction costs Current other financial assets include the security deposit granted in between the proceeds (net of transaction costs) and the redemption value is relation to the purchase of Argentinian assets (see Note 35) and short term recognised in the Consolidated Statement of Income over the period of the investments with original maturities up to twelve months and over three borrowings using the effective interest method. incurred. Borrowings are subsequently stated at amortised cost; any difference months. 2.18 Impairment of financial assets accruals basis using the effective interest method. Direct issue costs are charged to the Consolidated Statement of Income on an Provision against trade receivables is made when objective evidence is received that the Group will not be able to collect all amounts due to it in accordance with the original terms of those receivables. The amount of the 168 GeoPark 20-F 2.23 Share capital Equity comprises the following: Note 3 Financial Instruments-risk management • “Share capital” representing the nominal value of equity shares. The Group is exposed through its operations to the following financial risks: • “Share premium” representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share • Currency risk issuance. • “Other reserve” representing: • Price risk • Credit risk – concentration – the equity element attributable to shares granted according to IFRS 2 but • Funding and liquidity risk not issued at year end or, • Interest rate risk – the difference between the proceeds from the transaction with non- • Capital risk management controlling interests received against the book value of the shares acquired in the Chilean and Colombian subsidiaries. The policy for managing these risks is set by the Board of Directors. Certain • “Translation reserve” representing the differences arising from translation of risks are managed centrally, while others are managed locally following investments in overseas subsidiaries. guidelines communicated from the corporate department. The policy for each • “(Accumulated losses) Retained earnings” representing accumulated of the above risks is described in more detail below. earnings and losses. Currency risk 2.24 Share-based payment In Argentina, Colombia, Chile and Peru the functional currency is the US Dollar. The Group operates a number of equity-settled and cash-settled share-based The fluctuation of the local currencies of these countries against the US Dollar compensation plans comprising share awards payments to certain employees does not impact the loans, costs and revenue held in US Dollars; but it does and other third party contractors. Share-based payment transactions are impact the balances denominated in local currencies. Such is the case of the measured in accordance with IFRS 2. prepaid taxes. Fair value of the stock option plan for employee or contractors services In Chile, Colombia and Argentina subsidiaries most of the balances are received in exchange for the grant of the options is recognised as an expense. denominated in US Dollars, and since it is the functional currency of the The total amount to be expensed over the vesting period is determined subsidiaries, there is no exposure to currency fluctuation except from by reference to the fair value of the options granted calculated using the receivables or payables originated in local currency mainly corresponding to Geometric Brownian Motion method. VAT. Non-market vesting conditions are included in assumptions about the The Group minimises the local currency positions in Argentina, Colombia and number of options that are expected to vest. At each balance sheet date, the Chile by seeking to equilibrate local and foreign currency assets and liabilities. entity revises its estimates of the number of options that are expected to However, tax receivables (VAT) seldom match with local currency liabilities. vest. It recognises the impact of the revision to original estimates, if any, in Therefore the Group maintains a net exposure to them. the Consolidated Statement of Income, with a corresponding adjustment to equity. Most of the Group’s assets held in those countries are associated with oil and gas productive assets. Those assets, even in the local markets, are generally The fair value of the share awards payments is determined at the grant date settled in US Dollar equivalents. by reference of the market value of the shares and recognised as an expense over the vesting period. When the awards are exercised, the Company issues During 2017, the Argentine Peso devaluated by 17% (22% and 52% in new shares. The proceeds received net of any directly attributable transaction 2016 and 2015) against the US Dollar, the Chilean Peso revaluated by 8% costs are credited to share capital (nominal value) and share premium when (revaluated by 6% in 2016 and devaluated by 16% in 2015) and the Colombian the options are exercised. Peso revaluated by 1% (revaluated by 5% in 2016 and devaluated by 32% in For cash-settled share-based payment transactions, if any, the Company 2015). measures the services acquired for amounts that are based on the price of the If the Argentine Peso, the Chilean Peso and the Colombian Peso had each Company’s shares. The fair value of the liability incurred is measured using devaluated an additional 10% against the US dollar, with all other variables Geometric Brownian Motion method. Until the liability is settled, the Company held constant, post-tax loss for the year would have been higher by is required to remeasure the fair value of the liability at each reporting date US$ 1,538,000 (US$ 2,683,400 in 2016 and US$ 1,003,300 in 2015). and at the date of settlement, with any changes in value recognised in profit or loss for the period. In Brazil, the functional currency is the local currency, which is the Brazilian GeoPark 169 Real. The fluctuation of the US Dollars against the Brazilian Real does not inflation pursuant to the Brazilian General Market Price Index (Indice Geral impact the loans, costs and revenues held in Brazilian Real; but it does de Preços do Mercado), or IGPM. impact the balances denominated in US Dollars. Such is the case of the Itaú, which was fully repaid in September 2017, and intercompany loans. Most of If oil and methanol prices had fallen by 10% compared to actual prices the balances are denominated in Brazilian Real, and since it is the functional during the year, with all other variables held constant, considering the currency of the Brazilian subsidiary, there is no exposure to currency impact of the derivative contracts in place, post-tax loss for the year fluctuation except from the intercompany loan and the Itaú loan described would have been higher by US$ 10,423,000 (US$ 23,655,000 in 2016 and in Note 27. The exchange loss generated by the Brazilian subsidiary during US$ 23,940,000 in 2015). 2017 amounted to US$ 1,274,000 (gain of US$ 14,542,000 in 2016 and loss of US$ 35,605,000 in 2015). As of October 2016, GeoPark considered it was appropriate to manage part of the exposure to crude oil price volatility using derivatives. The During 2017, the Brazilian Real devaluated by 2% against the US Dollar Group considers these derivative contracts to be an effective manner of (revaluated by 17% in 2016 and devaluated by 47% in 2015, respectively). If properly managing commodity price risk. The price risk management the Brazilian Real had devaluated 10% against the US dollar, with all other activities mainly employ combinations of options and key parameters are variables held constant, post-tax loss for the year would have been higher by based on forecasted production and budget price levels. GeoPark has also US$ 3,100,000 (US$ 5,300,000 in 2016 and US$ 7,400,000 in 2015). obtained credit lines from industry leading counterparties to minimize the potential cash exposure of the derivative contracts (see Note 8). As of 31 December 2017, the balances denominated in the Peruvian local currency (Peruvian Soles) are not material. Credit risk – concentration As currency rate changes between the US Dollar and the local currencies, the credit risks correspond to the recognised values. There is not considered Group recognises gains and losses in the Consolidated Statement of Income. to be any significant risk in respect of the Group’s major customers and The Group’s credit risk relates mainly to accounts receivable where the hedging counterparties. Price risk The price realised for the oil produced by the Group is linked to US dollar In Colombia, during 2017, the Colombian subsidiary made 99% of the oil denominated crude oil international benchmarks. The market price of sales to Trafigura (one of the world’s leading independent commodity these commodities is subject to significant volatility and has historically trading and logistics houses), with Trafigura accounting for 79% of fluctuated widely in response to relatively minor changes in the global consolidated revenues for the same period. supply and demand for oil and natural gas, geopolitical landscape, economic conditions and a variety of additional factors. All the oil produced in Chile as well as the gas produced by TdF Blocks (5% of total revenue, 10% in 2016 and 15% in 2015) is sold to ENAP, the In Colombia, the realised oil price is linked to the Vasconia crude reference State owned oil and gas company. In Chile, most of gas production is sold price, a marker broadly used in the Llanos basin, adjusted for certain to the local subsidiary of Methanex, a Canadian public company (5% of marketing and quality discounts based on, among other things, API, consolidated revenue, 9% in 2016 and 7% in 2015). viscosity, sulphur content, water content, delivery point and transport costs. In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the State owned company, which is the operator of the Manati Field (10% of the In Chile, the oil price is based on Dated Brent minus certain marketing and consolidated revenue, 15% in 2016 and 2015). quality discounts such as, API, sulphur content and others. GeoPark has signed a long-term Gas Supply Contract with Methanex in the concentration of the credit risk, the Directors do not consider there to The forementioned companies all have good credit standing and despite Chile. The price of the gas sold under this contract is determined by a be a significant collection risk. formula that considers a basket of international methanol prices, including US Gulf methanol spot barge prices, methanol spot Rotterdam prices and In 2016 and 2017, the Group executed oil prices hedges via over-the- spot prices in Asia. counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative contracts. The Group’s hedging In Brazil, prices for gas produced in the Manati Field are based on a long- counterparties are leading financial institutions and trading companies, term off-take contract with Petrobras. The price of gas sold under this therefore the Directors do not consider there to be a significant collection contract is denominated in Brazilian Real and is adjusted annually for risk. See disclosure in Notes 8 and 25. 170 GeoPark 20-F Funding and Liquidity risk The Group analyses its interest rate exposure on a dynamic basis. Various In the past, the Group was able to raise capital through different sources of scenarios are simulated taking into consideration refinancing, renewal funding including equity, strategic partnerships and financial debt. During of existing positions, alternative financing and hedging. Based on these 2017, the Group placed US$ 425,000,000 notes (see Note 27). scenarios, the Group calculates the impact on profit and loss of a defined The Group is positioned at the end of 2017 with a cash balance of US$ all currencies. The scenarios are run only for liabilities that represent the major interest rate shift. For each simulation, the same interest rate shift is used for 134,755,000 and over 99% of its total indebtedness maturing in 2024. In interest-bearing positions. addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over 31,000 boepd in At 31 December 2017, the Group has no exposure to fluctuations in the production at year end. This scale and positioning permit the Group to protect interest rate, since its long-term borrowings were issued at fixed rate. At its financial condition and selectively allocate capital to the optimal projects 31 December 2016 and 2015, if 1% had been added to interest rates on subject to prevailing macroeconomic conditions. currency-denominated borrowings with all other variables held constant, post tax loss for the year would have been US$ 467,000 and US$ 507,000 higher, The indenture governing the Company Notes 2024 includes incurrence test respectively. covenants related to the compliance with certain thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply Capital risk management with the incurrence test covenants does not trigger an event of default. The Group’s objectives when managing capital are to safeguard the Group’s However, this situation may limit the Group’s capacity to incur additional ability to continue as a going concern in order to provide returns for indebtedness, as specified in the indenture governing the Notes. As of the shareholders and benefits for other stakeholders and to maintain an optimal date of these Consolidated Financial Statements, the Group is in compliance capital structure to reduce the cost of capital. with all the indenture’s provisions and covenants. The most significant funding transactions executed in 2017, 2016 and 2015 of the gearing ratio. This ratio is calculated as net debt divided by total capital. Consistent with others in the industry, the Group monitors capital on the basis include: Net debt is calculated as total borrowings (including ‘current and non-current borrowings’ as shown in the consolidated balance sheet) less cash and cash On September 2017, the Group successfully placed US$ 425,000,000 notes. equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated These Notes carry a coupon of 6.50% per annum and their final maturity will balance sheet plus net debt. be 21 September 2024. The net proceeds from the Notes were used by the Group to fully repay the 7.50% senior secured notes due 2020 and for general The Group’s strategy is to keep the gearing ratio within a 30% to 45% range, corporate purposes, including capital expenditures and repay other existing in normal market conditions. Due to the market conditions prevailing during indebtedness. 2017 and 2016 and the growing strategy of the Group, the gearing ratio at On December 2015, the Group announced the execution of an offtake and prepayment agreement with Trafigura, one of its customers. The prepayment The gearing ratios at 31 December 2017 and 2016 were as follows: year end is above such range. agreement provided GeoPark with access to up to US$ 100,000,000 in the form of prepaid future oil sales. The availability period for the prepayment Amounts in US$ ‘000 agreement expired on 30 September 2017. Funds committed by Trafigura are being repaid by the Group through future oil deliveries over 2.5 years Net Debt Total Equity with a six-month grace period. As of the date of these Consolidated Financial Total Capital Statements, outstanding balances related to the prepayment agreement Gearing Ratio 2017 291,449 126,840 418,289 70% 2016 285,109 141,593 426,702 67% amount to US$ 10,000,000. Interest rate risk Note 4 4. Accounting estimates and assumptions The Group’s interest rate risk arises from long-term borrowings issued at Estimates and assumptions are used in preparing the financial statements. variable rates, which expose the Group to cash flow to interest rate risk. Although these estimates are based on management’s best knowledge of The Group does not face interest rate risk on its US$ 425,000,000 Notes which and judgements are continually evaluated and are based on historical carry a fixed rate coupon of 6.50% per annum. As a consequence, the accruals experience and other factors, including expectations of future events that and interest payment are no substantially affected to the market interest rate are believed to be reasonable under the circumstances. current events and actions, actual results may differ from them. Estimates changes. GeoPark 171 The key estimates and assumptions used in these Consolidated Financial proven and probable reserves and incorporating the estimated future cost Statements are noted below: of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce • Cash flow estimates for impairment assessments of non-financial those reserves, the cost of the wells and future production facilities. assets require assumptions about two primary elements - future prices and reserves. Estimates of future prices require significant judgments • Obligations related to the abandonment of wells once operations are about highly uncertain future events. Historically, oil and gas prices terminated may result in the recognition of significant obligations. Estimating have exhibited significant volatility. The Group’s forecasts for oil and gas the future abandonment costs is difficult and requires management to revenues are based on prices derived from future price forecasts amongst make estimates and judgments because most of the obligations are many industry analysts and own assessments. Estimates of future cash flows are years in the future. Technologies and costs are constantly changing as well generally based on assumptions of long-term prices and operating and as political, environmental, safety and public relations considerations. The development costs. Group has adopted the following criterion for recognising well plugging and abandonment related costs: The present value of future costs necessary for Given the significant assumptions required and the possibility that actual well plugging and abandonment is calculated for each area at the present conditions will differ, management considers the assessment of impairment value of the estimated future expenditure. The liabilities recognised are based to be a critical accounting estimate (see Note 36). upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, • From time to time, the Group may be subject to various lawsuits, claims engineering and economic data. The estimation of economically and proceedings that arise in the normal course of business, including recoverable oil and natural gas reserves and related future net cash flows employment, commercial, tax, environmental, safety and health matters. was performed based on the Reserve Report as of 31 December 2017 For example, from time to time, the Group receives notice of environmental, prepared by DeGolyer and MacNaughton, an international consultancy to health and safety violations. Based on what the Management of the Group the oil and gas industry based in Dallas. It incorporates many factors and currently knows, it is not expected any material impact on the financial assumptions including: statements. – expected reservoir characteristics based on geological, geophysical and Note 5 engineering assessments; Consolidated Statement of Cash Flow – future production rates based on historical performance and expected The Consolidated Statement of Cash Flow shows the Group’s cash flows for the future operating and investment activities; year for operating, investing and financing activities and the change in cash – future oil and gas prices and quality differentials; and cash equivalents during the year. – assumed effects of regulation by governmental agencies; and – future development and operating costs. Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes in net working capital, Management believes these factors and assumptions are reasonable based and corporate tax. Income tax paid is presented as a separate item under on the information available to them at the time of preparing the estimates. operating activities. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available Cash flows from investing activities include payments in connection with the and as economic conditions impacting oil and gas prices and costs change. purchase and sale of property, plant and equipment and cash flows relating to the purchase and sale of enterprises to third parties, if any. • The Group adopts the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding Cash flows from financing activities include changes in equity, and proceeds whether an exploration asset should continue to be carried forward as an from borrowings and repayment of loans. exploration and evaluation asset not yet determined or when insufficient information exists for this type of cost to remain as an asset. In making this Cash and cash equivalents include bank overdraft and liquid funds with a term assessment Management takes professional advice from qualified experts. of less than three months. • Oil and gas assets held in property plant and equipment are mainly The following chart describes non-cash transactions related to the depreciated on a unit of production basis at a rate calculated by reference to Consolidated Statement of Cash Flow: 172 GeoPark 20-F Amounts in US$ ‘000 Increase in asset retirement obligation 2017 5,943 Increase in provisions for other long-term liabilities 2,053 2016 1,195 3,468 2015 985 Amounts in US$ ‘000 - Increase in Prepaid taxes Purchase of property, plant and equipment 11,759 (4,657) 830 (Increase) Decrease in Inventories (Increase) Decrease in Trade receivables (Increase) Decrease in Prepayments and 2017 2016 2015 (14,802) (2,351) (16,611) (2,031) (1,344) 466 (4,811) 2,752 22,470 Statement of Cash Flow are disclosed as follows: Changes in working capital shown in the Consolidated Note 6 Segment information other receivables and Other assets (8,623) Customer advance (repayments) payments (10,000) Security deposit granted (Note 35) (15,600) (1,758) 20,000 - 405 - - Increase (Decrease) in Trade and other payables 27,122 374 (33,120) (25,278) 11,920 (24,104) Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision- maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the 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 in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. The committee considers the business from a geographic perspective. The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit for the period before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful efforts, accrual of share-based payment, unrealized result on commodity risk 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. Segment areas (geographical segments): 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 costs Operating (loss) profit Operating netback Adjusted EBITDA Depreciation Write-off Total assets Employees (average) Employees at year end Chile Brazil Colombia Peru Argentina Corporate Total 32,738 15,873 16,865 - 34,238 263,076 910 262,309 33,328 - 767 (2,148) (20,999) (10,737) (66,913) (3,134) (24,236) (1,314) (1,211) (170) (18,304) (19,675) 11,222 4,070 - (39) (7,564) 4,434 23,540 20,166 (23,730) (10,809) (546) 301,931 (2,978) 91,604 (1,678) (248) (40,751) 116,290 194,013 168,303 (40,010) (1,625) 288,429 - - - - - - - - - 70 70 - - (338) (13) (80) - (245) - - - - - - - - - (3,850) (3,430) (14,773) - (467) - (3,505) (2,183) (11,075) (139) - (159) (685) (38) - 22,099 30,924 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) 786,163 102 102 12 12 164 180 13 19 88 92 - - 379 405 GeoPark 173 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 costs Operating (loss) profit Operating netback Adjusted EBITDA Depreciation Reversal of impaiment losses Write-off Total assets Employees (average) Employees at year end Amounts in US$ ‘000 2015 Revenue Sale of crude oil Sale of gas Production costs Royalties Transportation costs Share-based payment Other costs Operating (loss) profit Operating netback Adjusted EBITDA Depreciation Impairment loss Write-off Total assets Employees (average) Employees at year end Chile Brazil Colombia Peru Argentina Corporate Total 36,723 18,774 17,949 - (22,169) (1,495) (1,170) (138) (19,366) (44,969) 13,696 5,159 29,719 126,228 688 125,731 29,031 - (8,459) (2,721) - (71) (5,667) (645) 21,356 17,487 497 514 (36,607) (7,281) (1,111) (413) (27,802) 31,463 87,523 66,921 - - - - - - - - - - - - - - - - - - - - - - - - - - - (3,147) 41 (2,607) 370 (11,685) (378) 1,848 (91) (10,487) 192,670 145,193 47,477 514 (67,235) (11,497) (2,281) (622) (52,835) (28,613) 122,147 78,321 (31,355) (12,974) (31,148) (130) (150) (17) (75,774) - (19,389) 317,969 102 102 - (4,583) 99,904 5,664 (7,394) 182,784 - - - - - - 5,020 6,071 28,792 5,664 (31,366) 640,540 10 10 138 146 11 10 80 77 - - 341 345 Chile Brazil Colombia Peru Argentina Corporate Total 32,388 131,897 955 131,897 44,808 29,180 15,628 (28,704) (1,973) (2,441) (132) (24,158) (180,264) 15,254 (183) 31,433 (8,056) (2,998) - - (5,058) 6,639 24,393 20,460 (39,227) (13,568) (104,515) (25,751) 381,143 - - 114,974 - (48,534) (8,150) (2,068) (234) (38,082) (37,227) 80,355 66,736 (52,434) (45,059) (4,333) 153,071 - - - - - - - - (6,719) 44 (6,520) 597 597 - (1,448) (34) (2) (197) (1,215) (2,350) (1,732) (684) - - - - - - - - 209,690 162,629 47,061 (86,742) (13,155) (4,511) (563) (68,513) (12,570) (232,491) (287) 118,027 (6,022) 73,787 (129) (199) - - - - - - - 4,287 3,181 47,143 (105,557) (149,574) (30,084) 703,799 153 106 11 12 130 133 16 11 93 90 - - 403 352 Approximately 76% of capital expenditure was incurred by Colombia (67% in 2016 and 66% in 2015), 10% was incurred by Chile (20% in 2016 and 22% in 2015), 8% was incurred by Argentina (4% in 2016 and nil in 2015), 3% was incurred by Brazil (9% in 2016 and 12% in 2015) and 3% was incurred by Peru (nil in 2016 and 2015). 174 GeoPark 20-F 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 2017 2016 2015 Amounts in US$ ‘000 228,308 122,147 118,027 Sale of crude oil (38,937) (13,595) (32,323) (11,503) (30,590) Sale of gas (13,650) 2017 279,162 50,960 2016 145,193 47,477 2015 162,629 47,061 330,122 192,670 209,690 for reportable segments 175,776 78,321 73,787 Unrealized loss on commodity 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 Profit (Loss) before tax (13,300) (74,885) (4,075) (5,834) 1,314 78,996 (53,511) 2,016 (2,193) 25,308 (3,068) - Note 8 (75,774) (105,557) Commodity risk management contracts (3,367) (8,223) The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are zero-premium collars or zero- (25,702) (179,658) premium 3 ways (put spread plus call), and were placed with major financial 977 (12,840) institutions and commodity traders. The Group entered into the derivatives (28,613) (232,491) under ISDA Master Agreements and Credit Support Annexes, which provide (36,229) (36,924) credit lines for collateral posting thus alleviating possible liquidity needs 2,128 13,872 1,269 under the instruments and protect the Group from potential non-performance (33,474) risk by its counterparties. The Group’s derivatives are accounted for as non- (48,842) (301,620) hedge derivatives as of 31 December 2017 and therefore all changes in the fair values of its derivative contracts are recognised as gains or losses in the results (a) Net of capitalised costs for oil stock included in Inventories. (b) In 2015 includes termination costs (see Note 36). Also includes internally capitalised costs. The following table presents the Group’s derivative contracts in force as of 31 of the periods in which they occur. December 2017: Period 1 October 2017 - 31 March 2018 1 October 2017 - 31 March 2018 1 January 2018 - 30 June 2018 1 January 2018 - 30 June 2018 1 April 2018 - 30 June 2018 1 January 2018 - 30 June 2018 1 January 2018 - 30 June 2018 1 April 2018 - 30 June 2018 1 January 2018 - 30 June 2018 1 July 2018 - 30 September 2018 Reference ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT Type Volume bbl/d Price US$/bbl Zero Premium Collar Zero Premium Collar Zero Premium Collar Zero Premium Collar Zero Premium Collar Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way Zero Premium 3 Way 4,000 2,000 2,000 1,000 2,000 1,000 1,000 1,000 2,000 5,000 50.00 Put 54.90 Call 50.00 Put 54.95 Call 52.00 Put 60.00 Call 52.00 Put 58.40 Call 52.00 Put 58.25 Call 42.00-52.00 Put 59.55 Call 42.00-52.00 Put 59.50 Call 42.00-52.00 Put 59.60 Call 43.00-53.00 Put 64.55 Call 43.00-53.00 Put 69.00 Call The table below summarizes the gain (loss) on the commodity risk management contracts: Realized (loss) gain on commodity risk management contracts Unrealized loss on commodity risk management contracts Total 2017 (2,148) (13,300) (15,448) 2016 514 (3,068) (2,554) 2015 - - - GeoPark 175 Note 9 Production and operating costs Amounts in US$ ‘000 Well and facilities maintenance Staff costs (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 Note 10 Depreciation Amounts in US$ ‘000 Oil and gas properties Production facilities and machinery Furniture, equipment and vehicles Buildings and improvements Depreciation of property, plant and equipment (a) Related to: Productive assets Administrative assets Depreciation total (a) Directors’ Remuneration Note 11 Staff costs and Directors Remuneration 2015 19,974 17,999 Number of employees at year end Amounts in US$ ‘000 2017 405 2016 345 2015 352 563 Wages and salaries 44,891 36,059 40,574 2017 14,722 15,017 457 28,697 11,902 2,969 5,818 2,591 6,069 2,377 1,213 7,155 2016 13,160 10,859 622 11,497 8,283 2,281 3,868 2,222 6,300 1,687 1,082 5,374 13,155 Share-based payments (Note 30) 8,591 4,511 3,517 3,239 2,878 2,645 2,127 7,543 Social security charges Director’s fees and allowance Recognised as follows: Production and operating costs Geological and geophysical expenses Administrative expenses 98,987 67,235 86,742 Board of Directors’ and key managers’ remuneration Salaries and fees 2015 Share-based payments Other benefits in kind 84,849 15,467 2,850 874 2017 57,725 14,558 1,948 844 2016 61,080 10,788 2,702 920 4,075 5,364 3,458 3,367 3,792 2,088 8,223 6,197 1,238 57,788 45,306 56,232 15,474 11,026 31,288 57,788 11,481 10,439 23,386 45,306 18,562 11,336 26,334 56,232 9,674 2,322 287 12,283 7,337 1,211 112 8,660 6,549 6,544 167 13,260 75,075 75,490 104,040 72,283 2,792 75,075 71,868 3,622 100,316 3,724 75,490 104,040 (a) Depreciation without considering capitalised costs for oil stock included in Inventories. Executive Directors’ Executive Directors’ Non-Executive Director Fees Paid in Cash Equivalent Fees Bonus Directors’ Fees (in US$) Shares (No. of Shares) Total Remuneration Gerald O’Shaughnessy James F. Park Pedro Aylwin (a) Peter Ryalls (b) Juan Cristóbal Pavez (c) Carlos Gulisano Robert Bedingfield (d) Michael Dingman Jamie Coulter US$ 400,000 US$ 800,000 - US$ 800,000 - - - - - - - - - - - - - US$ 115,000 US$ 110,000 US$ 110,000 US$ 102,500 US$ 46,667 US$ 50,000 - - - 9,388 15,408 15,408 15,408 8,853 8,015 US$ 400,000 US$ 1,600,000 - US$ 165,010 US$ 210,020 US$ 210,020 US$ 202,520 US$ 105,012 US$ 112,519 a Pedro Aylwin has a service contract that provides for him to act as Manager of Corporate Governance so he resigned his fees as Director. b Technical Committee Chairman until his death. Afterwards the Chairman is Carlos Gulisano. c Compensation Committee Chairman. d Audit Committee Chairman. 176 GeoPark 20-F The non-executive Directors annual fees correspond to US$ 80,000 to be Note 15 settled in cash and US$ 100,000 to be settled in stocks, paid quarterly in equal Financial costs installments. In the event that a non-executive Director serves as Chairman of any Board Committees, an additional annual fee of US$ 20,000 shall apply. Amounts in US$ ‘000 2017 2016 2015 A Director who serves as a member of any Board Committees shall receive Financial expenses an annual fee of US$ 10,000. Total payment due shall be calculated in an Interest and amortisation aggregate basis for Directors serving in more than one Committee. The of debt issue costs Chairman fee shall not be added to the member’s fee for the same Committee. Interest with related parties Payments of Chairmen and Committee members’ fees shall be made quarterly Less: amounts capitalised in arrears and settled in cash only. Note 12 on qualifying assets Borrowings cancellation costs Bank charges and other financial costs Unwinding of long-term liabilities Geological and geophysical expenses (Note 28) Amounts in US$ ‘000 Staff costs (Note 11) Share-based payment (Notes 11) Allocation to capitalised project Other services 2017 10,525 501 (6,402) 3,070 7,694 2016 9,541 898 (2,119) 1,962 10,282 2015 Financial income 10,557 Interest received 779 (598) 3,093 13,831 Foreign exchange gains and losses Foreign exchange (loss) gain Total Financial results (27,823) (2,224) (28,984) (1,587) (28,983) (1,560) 611 (17,575) (3,721) 255 - 637 - (3,220) (4,443) (2,779) (2,693) (2,575) (53,511) (36,229) (36,924) 2,016 2,016 2,128 2,128 1,269 1,269 (2,193) (2,193) 13,872 13,872 (53,688) (20,229) (33,474) (33,474) (69,129) 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 Note 14 Selling expenses Amounts in US$ ‘000 Transportation Selling taxes and other Note 16 Tax reforms in Colombia 2017 24,713 3,117 5,120 2,506 2,772 3,458 2,109 (7,646) 5,905 42,054 2016 19,451 1,847 3,894 2,217 1,717 2,088 2,013 (4,365) 5,308 34,170 2015 A tax reform has been enacted in Colombia during December 2016. The 18,215 legislation included significant changes to certain corporate income tax and statutory income tax provisions, including rate reductions and the repeal of certain corporate-level taxes. The legislation also aimed to raise tax revenue mostly by increasing the rate of the value added tax (VAT) to 19% (from 16%) and through a variety of excise taxes. Most of the tax provisions were effective 1 January 2017. 6,881 4,115 2,535 1,497 1,238 1,791 (4,203) The legislation also included the following provisions that are intended to 5,402 simplify the corporate income tax system by: 37,471 • Eliminating the “CREE” tax on corporations and the CREE surtax (CREE is the Spanish acronym for the “fairness tax”). • Introducing a temporary income surtax of 6% for 2017 and 4% for 2018. 2017 864 272 1,136 2016 3,559 663 4,222 2015 4,760 451 5,211 Accordingly, with this tax reform, the corporate income tax will have the following rate schedule (applied beyond a limited profit threshold):  – 40% in 2017 (34% income tax plus 6% income surtax) – 37% in 2018 (33% income tax plus 4% income surtax) – 33% in 2019. There is an increase in the tax rate on deemed income relating to increases in a taxpayer’s net worth (i.e., the increase in the value of a taxpayer’s assets); the rate is increased from 3% to 3.5%.  GeoPark 177 Other changes to the income tax law are the following: • New withholding tax on dividends—with the applicable rates for non-resident shareholders of: (1) 5% for dividends distributed out of the Note 17 Income tax distributing entity’s previously taxed profits; and (2) 35% for dividends Amounts in US$ ‘000 distributed out of the distributing entity’s previously untaxed profits, plus an Current tax additional 5% after having applied and deducted the initial 35% withholding. Deferred income tax (Note 18) • A general 15% withholding tax rate for taxable income accrued by non- residents without a permanent establishment (certain special rates may 2017 2016 (48,449) (12,359) 5,304 555 (43,145) (11,804) 2015 (7,262) 24,316 17,054 apply). The tax on the Group’s profit (loss) before tax differs from the theoretical • Lengthen the statute of limitations with respect to tax returns and amount that would arise using the weighted average tax rate applicable to assessments. • Limit loss carryforwards to 12 years. • Allow for a deduction of VAT paid on certain acquisitions or imports of profits of the consolidated entities as follows: capital goods when calculating the taxpayer’s income tax liability. Amounts in US$ ‘000 • Retain the tax on long-term capital gains at 10% for both corporations and Profit (loss) before tax 2017 25,308 2016 2015 (48,842) (301,620) non-residents. Tax losses from non-taxable jurisdictions The legislation also revises and refines tax accounting standards based on Taxable loss (profit) 22,708 48,016 12,318 15,852 (36,524) (285,768) IFRS rules. Tax reforms in 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 (31,107) (809) 62,589 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 income tax is recognised 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. Non recoverable tax loss carry-forwards Non-taxable results (a) Income tax (8,111) (2,330) (6,616) (2,840) (16,325) (6,776) 542 - 220 - (2,139) (1,759) (43,145) (11,804) (625) (15,537) (6,272) 17,054 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 (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 40%. 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 Argentina Chile (a) Brazil (a) Total tax losses at 31 December 2017 4,849 345,104 33,721 2016 2,908 280,290 16,057 2015 3,834 209,910 - 383,674 299,255 213,744 178 GeoPark 20-F (a) Taxable losses have no expiration date. At the balance sheet date deferred tax assets in respect of tax losses in Note 18 Argentina and in certain Companies in Chile have not been recognised as Deferred income tax there is insufficient evidence of future taxable profits to offset them (in the The gross movement on the deferred income tax account is as follows: case of Argentina, before the statute of limitation of these tax losses causes them to expire). Expiring dates for tax losses accumulated at 31 December 2017 are: Amounts in US$ ‘000 Deferred tax at 1 January Reclassification (a) Currency translation differences Amounts in US$ ‘000 Income statement credit 2017 20,283 - (237) 5,304 2016 17,691 574 1,463 555 754 Deferred tax at 31 December 25,350 20,283 1,446 2,649 (a) Corresponds to differences between income tax provision and the final tax return presented. Expiring date 2020 2021 2022 The breakdown and movement of deferred tax assets and liabilities as of 31 December 2017 and 2016 are as follows: Amounts in US$ ‘000 Deferred tax assets Difference in depreciation rates and other Taxable losses Total 2017 Total 2016 Amounts in US$ ‘000 Deferred tax liabilities Difference in depreciation rates and other Taxable losses Total 2017 At the beginning Currency translation (Charged) / At end of year of year 19,225 3,828 23,053 34,646 differences credited to net profit (237) - (237) 1,463 (2,817) 7,637 4,820 (13,056) 16,171 11,465 27,636 23,053 At the beginning Credited to net profit Reclassification (a) At end of year of year (17,308) 14,538 (2,770) (2,766) 3,250 484 13,611 - - - 574 (20,074) 17,788 (2,286) (2,770) Total 2016 (a) Corresponds to differences between income tax provision and the final tax return presented. (16,955) Note 19 Earnings per share Amounts in US$ ‘000 except for shares 2017 (a) 2016 2015 Weighted average number of shares used in basic EPS 60,093,191 59,777,145 57,759,001 Amounts in US$ ‘000 except for shares 2017 2016 2015 Numerator: Loss for the year attributable to owners (24,228) (49,092) (234,031) Effect of dilutive potential common shares (a) Weighted average number of common shares for the purposes of diluted earnings Denominator: Weighted average number of shares used in basic EPS (Losses) after tax 60,093,191 59,777,145 57,759,001 per shares 60,093,191 59,777,145 57,759,001 (Losses) Earnings after tax per share (US$) – basic (0.40) (0.82) (4.05) per share (US$) – diluted (0.40) (0.82) (4.05) (a) For the year ended 31 December 2017, there were 4,564,777 (1,390,706 in 2016 and 1,032,279 in 2015) of potential shares that could have a dilutive impact but were considered antidilutive due to negative earnings. GeoPark 179 Note 20 Property, plant and equipment Amounts in US$ ‘000 Cost at 1 January 2015 Additions Currency translation differences Disposals Write-off / Impairment loss Transfers Cost at 31 December 2015 Additions Currency translation differences Disposals Write-off / Impairment reversal Transfers Cost at 31 December 2016 Additions Currency translation differences Disposals Write-off / Impairment reversal Transfers Cost at 31 December 2017 Depreciation and write-down at 1 January 2015 (240,439) Depreciation Disposals Currency translation differences (84,849) - 4,115 Depreciation and write-down at 31 December 2015 (321,173) Depreciation Disposals Currency translation differences (61,080) - (2,486) Depreciation and write-down at 31 December 2016 (384,739) Depreciation Disposals Currency translation differences (57,725) - 930 Oil & gas Furniture, Production Buildings and Construction Exploration Total properties equipment facilities and improvements in progress 749,947 (4,640)(a) (27,522) (241) (128,956) 60,404 648,992 (3,531) (a) 16,132 - 5,664 24,984 692,241 7,997 (a) (1,142) - - 77,408 776,504 and vehicles machinery 12,057 111,646 9,527 954 (182) (13) - 929 13,745 406 126 (22) - 102 - (2,577) (1,685) (13,242) 30,690 124,832 466 2,077 - - 5,038 272 (92) (84) - 895 10,518 - 35 - - - 14,357 132,413 10,553 954 (12) (112) - 211 15,398 (4,449) (2,850) 8 (26) (7,317) (2,702) 8 (38) (10,049) (1,948) 73 8 - (147) - - 25,130 157,396 (45,147) (15,467) - - (60,614) (10,788) - (296) (71,698) (14,558) - 24 - (3) (189) - - 10,361 (2,244) (874) 15 (92) (3,195) (920) - (16) (4,131) (844) 38 5 59,425 36,543 - - (7,376) (58,769) 29,823 20,322 73 - - (17,292) 32,926 66,953 (62) - - (61,827) 37,990 - - - - - - - - - - - - - and evaluation assets(b) 140,444 12,299 (1,510) - (30,084) (c) (34,149) 87,000 18,181 790 - (31,366) (d) (12,832) 61,773 49,455 (104) - (5,834) (e) (40,922) 1,083,046 45,428 (31,883) (2,023) (179,658) - 914,910 35,844 19,233 (22) (25,702) - 944,263 125,359 (1,470) (301) (5,834) - 64,368 1,062,017 - - - - - - - - - - - - - (292,279) (104,040) 23 3,997 (392,299) (75,490) 8 (2,836) (470,617) (75,075) 111 967 (544,614) 522,611 473,646 517,403 Depreciation and write-down at 31 December 2017 (441,534) (11,916) (86,232) (4,932) Carrying amount at 31 December 2015 Carrying amount at 31 December 2016 Carrying amount at 31 December 2017 327,819 307,502 334,970 6,428 4,308 3,482 64,218 60,715 71,164 7,323 6,422 5,429 29,823 32,926 37,990 87,000 61,773 64,368 (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$ 53,764,000 (US$ 53,523,000 in 2016 and US$ 64,094,000 in 2015). 180 GeoPark 20-F Amounts in US$ ‘000 Exploration wells at 31 December 2015 Additions Write-offs Transfers Exploration wells at 31 December 2016 Additions Write-offs Transfers Exploration wells at 31 December 2017 Total 22,906 15,088 (19,949) (9,795) 8,250 35,299 (3,664) (29,281) 10,604 As of 31 December 2017, there were two exploratory wells that have been capitalised for a period less than a year amounting to US$ 4,488,000 and two exploratory wells that have been capitalised for a period over a year amounting to US$ 6,116,000. (c) Corresponds to the cost of two unsuccessful exploratory wells in Colombia (one well in CPO4 Block and one well in Llanos 32). The charge also includes the loss generated by the write-off of the seismic cost for Flamenco Block in Chile generated by the relinquishment of 143 sq km in November 2015 and the write off of two wells drilled in previous years in the same block for which no additional work would be performed. (d) 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. (e) 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. GeoPark 181 Note 21 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of 31 December 2017 (a): (a) LGI is not a subsidiary, it is Non-controlling interest. Non controlling interest held by LGI: • Consolidated Statement of Comprehensive Income: Total comprehensive income for the year 2017 include a profit of US$ 13,536,000 (profit of US$ 2,791,000 in 2016 and loss of US$ 7,085,000 in 2015), a loss of US$ 6,200,000 (US$ 10,379,000 in 2016 and US$ 33,260,000 in 2015) and a loss of US$ 945,000 (US$ 3,966,000 in 2016 and US$ 10,190,000 in 2015) corresponding to non-controlling interest 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 includes US$ 29,330,000 (US$ 16,168,000 in 2016), US$ 15,953,000 (US$ 22,082,000 in 2016) and a negative amount of US$ 3,368,000 (US$ 2,422,000 in 2016) corresponding to non-controlling interest 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$ 479,000 in 2017 (US$ 6,406,000 in 2016) correspond to non-controlling interest held by LGI in GeoPark Colombia Coöperatie U.A. 182 GeoPark 20-F 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 GeoPark Latin America Limited (Bermuda) GeoPark Latin America Limited – Agencia en 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 SAS (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 Brazil 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) Yamu/Carupana Block (Colombia) Llanos 34 Block (Colombia) Llanos 32 Block (Colombia) CPO-4 Block (Colombia) Puelen Block (Argentina) Sierra del Nevado Block (Argentina) CN-V Block (Argentina) Manati Field (Brazil) (a) Indirectly owned. (b) Dormant companies. (c) LG International has 20% interest. (d) LG International has 20% interest through GeoPark Chile S.A. and a 14% direct interest, totaling 31.2%. (e) GeoPark is the operator. Corporate structure reorganization Ownership interest 100% 100% (a) 100% 100% (a) 100% (a) (b) 100% (a) 80% (a) (c) 80% (a) (c) 80% (a) (c) 68.8% (a) (d) 100% (a) (b) 80% (a) (c) 100% (a) 80% (a) (c) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) 100% (a) (b) 100% (a) (b) 100% (b) 51% (a) (b) 100% 50% (e) 50% (e) 50% (e) 60% (e) 89.5%/100% (e) 45% (e) 12.5% 50% (e) 18% 18% 50% (e) 10% During 2017, the Company decided to incorporate a subsidiary in the United Kingdom to conduct the businesses in Latin America by adopting all the key resolutions and decisions necessary for such purpose. Also, a tax reform enacted in The Netherlands during September 2017 that would harm the Group´s cashflow, forced the Group to decide the re-domiciliation of its 100% owned Dutch subsidiaries to Spain. GeoPark 183 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 Amounts in US$ ‘000 At 1 January Foreign exchange (income) loss 2016 14,052 2017 741 (147) 594 2016 596 145 741 4,517 The credit period for trade receivables is 30 days. The maximum exposure to 98 credit risk at the reporting date is the carrying value of each class of receivable. 2017 27,674 1,258 939 29,871 18,667 The Group does not hold any collateral as security related to trade receivables. 26,048 3,823 29,871 15,815 The carrying value of trade receivables is considered to represent a reasonable 2,852 approximation of its fair value due to their short-term nature. 18,667 Note 25 Financial instruments by category 2017 1,969 3,769 5,738 2016 1,521 1,994 3,515 Amounts in US$ ‘000 Loans and receivables Trade receivables To be recovered from co-venturers (Note 33) Other financial assets (a) Cash and cash equivalents Assets as per statement of financial position 2017 2016  19,519 2,455 43,488 134,755 18,426 3,311 22,027 73,563 200,217 117,327 Liabilities as per statement of financial position 2017 2016 19,289 19,289 52,557 31,184 10,015 3,067 3,067 23,650 27,801 1,614 426,204 358,672 519,960 411,737 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 Total Classified as follows: Current Non current Total 2017 19,519 19,519 2,455 56 5,242 7,753 27,272 27,037 235 27,272 (a) Non current other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government 2016 18,426 regulations and also include a non current account receivable with the 18,426 previous owners of one of the Colombian subsidiaries (see Note 28). Current 3,311 other financial assets corresponds to the security deposit granted in relation to 42 the purchase of Argentinian assets (see Note 35) and short term investments 4,290 with original maturities up to twelve months and over three months. 7,643 26,069 Amounts in US$ ‘000 25,828 Liabilities at fair value through profit and loss 241 Derivative financial instrument liabilities 26,069 Other financial liabilities at amortised cost Trade receivables that are aged by less than three months are not considered Trade payables impaired. As of 31 December 2017 and 2016, there are no balances that were Payables to related parties (Note 33) aged by more than 3 months, but not impaired. These relate to customers for To be paid to co-venturers (Note 33) whom there is no recent history of default. There are no balances overdue Borrowings between 31 days and 90 days as of 31 December 2017 and 2016. Movements on the Group provision for impairment are as follows: Total financial liabilities 539,249 414,804 184 GeoPark 20-F Credit quality of financial assets Amounts in US$ ‘000 Less than Between 1 Between 2 The credit quality of financial assets that are neither past due nor impaired can 1 year and 2 years and 5 years Over 5 years be assessed by reference to external credit ratings (if available) or to historical At 31 December 2017 information about counterparty default rates: Amounts in US$ ‘000 Trade receivables Borrowings Trade payables Payables 2017 2016 to related parties Counterparties with an external credit rating (Moody’s) At 31 December 2016 B2 Ba3 Baa3 Counterparties without an external credit rating Group1 (a) Total trade receivables 70 8,788 3,614 7,056 Borrowings - Trade payables 3,729 Payables to related parties 7,047 19,519 7,641 18,426 27,625 52,557 7,331 87,513 48,958 23,650 27,625 82,875 480,250 - - - - 2,068 27,087 29,693 109,962 480,250 43,304 355,064 - - 1,561 74,169 1,561 22,018 44,865 377,082 - - - - (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 Accounting policies for financial instruments have been applied to classify as either: loans and receivables, held-to-maturity, available-for-sale, or fair Fair value measurement of financial instruments denominated in Brazilian Real. Cash at bank and other financial assets (a) Amounts in US$ ‘000 Counterparties with an external credit rating (Moody’s, 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 of fair value measurements by level according to the following fair value 2017 2016 measurement hierarchy: S&P, Fitch, BRC Investor Services) • Level 1 - Quoted prices (unadjusted) in active markets for identical assets or A1 A2 A3 Aaa Aa3 AAA B2 Ba1 Ba2 Baa1 Baa2 Ba3 B3 BBB Counterparties without an external credit rating 553 298 63,853 15,040 11,401 19,634 31 18 7 307 4,078 2,815 - 15,064 45,123 813 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). 42,798 • Level 3 - Inputs for the asset or liability that are not based on observable 14 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 100 annual financial report. 4,094 3,497 10 - (a) Fair value hierarchy The following table presents the Group’s financial assets and financial liabilities measured and recognised at fair value at 31 December 2017 and 2016 on a 44,252 recurring basis: Total 178,222 95,578 Amounts in US$ ‘000 Level 2 At 31 December 2017 (a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 21,000 (US$ 12,000 in 2016). Liabilities Financial liabilities - contractual undiscounted cash flows Derivative financial instrument liabilities Commodity risk management contracts The table below analyses the Group’s financial liabilities into relevant Total Liabilities maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows. 19,289 19,289 19,289 19,289 GeoPark 185 Amounts in US$ ‘000 Level 2 At 31 December 2016 Note 26 Liabilities Derivative financial instrument liabilities Commodity risk management contracts Total Liabilities 3,067 3,067 Share capital Issued share capital 3,067 Common stock (amounts in US$ ‘000) 3,067 The share capital is distributed as follows: 2017 61 2016 60 There were no transfers between Level 2 and 3 during the period. Total common shares in issue 60,596,219 59,940,881 Common shares, of nominal US$ 0.001 60,596,219 59,940,881 The Group did not measure any financial assets or financial liabilities at fair Authorised share capital value on a non-recurring basis as at 31 December 2017. US$ per share 0.001 0.001 (b) Valuation techniques used to determine fair values Number of common shares Specific valuation techniques used to value financial instruments include: (US$ 0.001 each) Amount in US$ The use of quoted market prices or dealer quotes for similar instruments. 5,171,949,000 5,171,949,000 5,171,949 5,171,949 The market-to-market fair value of the Group’s outstanding derivative Details regarding the share capital of the Company are set out below: instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of Common shares counterparty credit risk and are within level 2 of the fair value hierarchy. As of 31 December 2017, the outstanding common shares confer the The fair value of the remaining financial instruments is determined using following rights on the holder: discounted cash flow analysis. All of the resulting fair value estimates are • the right to one vote per share; included in level 2. • ranking pari passu, the right to any dividend declared and payable on (c) Fair values of other financial instruments (unrecognised) 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 GeoPark common common shares; Shares issued Shares closing US$(`000) instruments, the fair values are not materially different to their carrying shares history Date (millions) (millions) Closing amounts, since the interest receivable/payable is either close to current Shares outstanding market rates or the instruments are short-term in nature. at the end of 2015 Stock awards Borrowings are comprised primarily of fixed rate debt and variable rate debt Stock awards with a short term portion where interest has already been fixed. They are Stock awards classified under other financial liabilities and measured at their amortized Buyback program cost. Shares outstanding at the end of 2016 The fair value of these financial instruments at 31 December 2017 amounts to Stock awards US$ 425,118,000 (US$ 346,180,000 in 2016). The fair values are based on cash Stock awards flows discounted using a rate based on the borrowing rate of 6.90% (7.60% in Stock awards 2016) and are within level 2 of the fair value hierarchy. Shares outstanding at the end of 2016 Feb 2016 Dec 2016 Dec 2016 Dec 2016 Jan 2017 Dec 2017 Dec 2017 0.4 0.5 0.1 (0.6) 0.1 0.1 0.5 59.5 59.9 60.4 60.5 59.9 59.9 60.0 60.1 60.6 60.6 59 60 60 60 60 60 60 60 61 61 Stock Award Program and Other Share Based Payments On 14 December 2017, 490,000 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 2,513,000. On 15 December 2016, 379,500 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 3,940,000. 186 GeoPark 20-F On 12 November 2015 and 22 December 2015, 817,600 and 478,000 Note 27 common shares were allotted to the trustee of the Employee Beneficiary Borrowings Trust (“EBT”), generating a share premium of US$ 11,359,000 and US$ 3,577,000, respectively. Amounts in US$ ‘000 2017 2016 In January 2017, 82,306 shares were issued to key management as bonus compensation, generating a share premium of US$ 332,000.  On 8 February 2016, 468,405 shares were issued to Executive Directors and key management as bonus compensation, generating a share premium of US$ 1,512,000.  Outstanding amounts as of 31 December 2024 Notes (a) Notes GeoPark Latin America Agencia en Chile (b) Banco Itaú (c) Banco de Chile (d) Banco de Crédito e Inversiones (e) Classified as follows: On 13 September 2017, 12,546 shares were issued pursuant to a consulting Current agreement for services rendered to GeoPark Limited generating a share Non current premium of US$ 43,000. 426,124 - - - 80 - 304,059 49,763 4,709 141 426,204 358,672 7,664 418,540 39,283 319,389 On 6 September 2016, 8,333 shares were issued pursuant to a consulting (a) During September 2017, the Company successfully placed US$ 425,000,000 notes which were offered to qualified institutional buyers in accordance with agreement for services rendered to GeoPark Limited generating a share Rule 144A under the United States Securities Act, and outside the United premium of US$ 38,000. States to non-U.S. persons in accordance with Regulation S under the United States Securities Act. On 30 November 2015, 720,000 new common shares were issued to the Executive Directors, generating a share premium of US$ 7,309,000.  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 pledge of all During 2017, the Company issued 70,485 (137,897 in 2016 and 99,555 in of the equity interests of the Company, directly or indirectly, in GeoPark 2015) shares to Non-Executive Directors in accordance with contracts as Colombia Coöperatie U.A. and GeoPark Chile S.A.. The debt issuance cost for compensation, generating a share premium of US$ 257,000 (US$ 541,848 in this transaction amounted to US$ 6,683,000 (debt issuance effective rate: 2016 and US$ 486,692 in 2015). The amount of shares issued is determined 6.90%). The indenture governing the Notes due 2024 includes incurrence test considering the contractual compensation and the fair value of the shares for covenants that provides among other things, that, during the first two years each relevant period. Buyback Program from the issuance date, the Net Debt to Adjusted EBITDA ratio should not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2 times. Failure to comply with the incurrence test covenants does not trigger On 19 December 2014, the Company approved a program to repurchase an event of default. However, this situation may limit the Company’s capacity up to US$ 10,000,000 of common shares, par value US$ 0.001 per share of to incur additional indebtedness, as specified in the indenture governing the the Company (the “Repurchase Program”). The Repurchase Program began Notes. Incurrence covenants as opposed to maintenance covenants must be on 19 December 2014 and was resumed on 14 April 2015 and then on tested by the Company before incurring additional debt or performing certain 10 June 2015, expiring on 18 August 2015. During 2016, the Repurchase corporate actions including but not limited to dividend payments, restricted Program began on 6 April 2016 and then was resumed during the year until payments and others, (other than in each case, certain specific exceptions). November 2016. The Shares repurchased will be used to offset, in part, any As of the date of these Consolidated Financial Statements, the Company is in expected dilution effects resulting from the Group’s employee incentive compliance of all the indenture’s provisions and covenants. schemes, including grants under the Company’s Stock Award Plan and the Limited Non-Executive Director Plan. In 2017, no shares were repurchased. The net proceeds from the Notes were used by the Company (i) to make a During 2016 and 2015, the Company purchased 588,868 and 370,074 73,082 capital contribution to its wholly-owned subsidiary, GeoPark Latin America common shares for a total amount of US$ 1,991,000 and US$ 1,615,000, Limited Agencia en Chile (“GeoPark LA Agencia”), providing it with sufficient respectively. These transactions had no impact on the Group’s results. funds to fully repay the 7.50% senior secured notes due 2020 and to pay any related fees and expenses, including call premium, and (ii) for general corporate purposes, including capital expenditures and to repay existing indebtedness. (b) During February 2013, the Group successfully placed US$ 300,000,000 notes which were offered under Rule 144A and Regulation S exemptions of the GeoPark 187 United States Securities laws. The Notes carried a coupon of 7.50% per annum The provision for asset retirement obligation relates to the estimation of future and mature on 11 February 2020. These Notes were fully repaid in September disbursements related to the abandonment and decommissioning of oil and 2017. gas wells (see Note 4). (c) During March 2014, GeoPark executed a loan agreement with Itaú BBA International for US$ 70,450,000 to finance the acquisition of a 10% working Deferred income relates to contributions received to improve the project economics of the gas wells in Chile. The amortisation is in line with the related interest in the Manatí field in Brazil. The loan was fully repaid in September asset. The addition in 2016 and the amounts used in 2017 correspond to the 2017. deferred income related to the take or pay provision associated to gas sales in Brazil. (d) During December 2015, GeoPark executed a loan agreement with Banco de Chile for US$ 7,028,000 to finance the start-up of new Ache gas field As of 31 December 2016, Other included a provision for an amount of US$ in GeoPark-operated Fell Block. The interest rate applicable to this loan is 5,636,000 related to fiscal controversies associated to income taxes in one of LIBOR plus 2.35% per annum. The interest and the principal have been paid the Colombian subsidiaries. These controversies related to fiscal periods prior on monthly basis; with a six months grace period, with final maturity on to the acquisition of these subsidiaries by the Group. During 2017, GeoPark December 2017. As of the date of these Consolidated Financial Statements, settled the controversies by paying a total amount of US$ 3,389,000 to the tax the loan was fully repaid. authority, under a valid tax amnesty. In connection to this, the Group recorded an account receivable with the previous owners for the amount paid under (e) During February 2016, GeoPark executed a loan agreement with Banco de Crédito e Inversiones for US$ 186,000 to finance the acquisition of vehicles the tax amnesty, considering the contractual right of recovering amounts paid related to fiscal years prior to the acquisition. This account receivable for the Chilean operation. The interest rate applicable to this loan is 4.14% per is recognised under other financial assets in the balance sheet. In addition, annum. The interest and the principal will be paid on monthly basis, with final actions taken by the Group to maximize ongoing work projects and to reduce maturity on February 2019. expenses, including renegotiations and reduction of oil and gas service contracts and other initiatives included in the cost cutting program adopted As of the date of these Consolidated Financial Statements, the Group has may expose the Group to claims and contingencies from interested parties available credit lines for over US$ 33,000,000. that may have a negative impact on its business, financial condition, results of operations and cash flows. So, the additions in 2016 reflects the future contingent payments in connection with claims of third parties. Note 28 Provisions and other long-term liabilities Amounts in US$ ‘000 Asset retirement Deferred obligation Income At 1 January 2016 Addition to provision Recovery of abandonments costs Exchange difference 31,617 1,195 (5,504) (1,614) Foreign currency translation 1,614 5,033 1,375 - - - Amortisation Unwinding of discount At 31 December 2016 Addition to provision Exchange difference Foreign currency translation Amortisation Unwinding of discount Unused amounts reversed Amounts used during - (2,924) 2,554 29,862 - 3,484 5,943 134 (134) - 2,607 - - - - (657) - - the year At 31 December 2017 (337) 38,075 (1,375) 1,452 188 GeoPark 20-F Other 5,800 2,686 - 538 - - 139 9,163 2,220 1,154 - - 172 (2,535) (3,417) 6,757 Note 29 Trade and other payables Total Amounts in US$ ‘000 42,450 V.A.T 5,256 (5,504) (1,076) Trade payables Payables to related parties(a) (Note 33) Customer advance payments (Note 3) Staff costs to be paid 1,614 Royalties to be paid (2,924) Taxes and other debts to be paid 2,693 To be paid to co-venturers (Note 33) Classified as follows: Current Non current 42,509 8,163 1,288 (134) (657) 2,779 (2,535) (a)The outstanding amount corresponds to advanced cash call payments granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s blocks. The expected maturity of these balances is July 2020 and the (5,129) applicable interest rate is 8% per annum. 46,284 2017 1,118 52,557 31,184 10,000 9,143 4,110 4,191 10,015 122,318 96,397 25,921 2016 1,102 23,650 27,801 20,000 7,749 1,503 3,355 1,614 86,774 52,008 34,766 The average credit period (expressed as creditor days) during the year ended During 2016, the Group approved a share-based compensation program for 31 December 2017 was 95 days (2016: 83 days) 1,619,105 shares. Main characteristics of the Stock Awards Programs are: The fair value of these short-term financial instruments is not individually • Exercise price is equal to the nominal value of shares. determined as the carrying amount is a reasonable approximation of fair value. • Vesting period is three years. • All employees are eligible. Note 30 Share-based payment • 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. IPO Award Program and Executive Stock Option plan The Group has established different stock awards programs and other share- Also during 2016, the Group approved a plan named Value Creation Plan based payment plans to incentivise the Directors, senior management and (“VCP”) oriented to Top Management. Main characteristics of the VCP are: employees, enabling them to benefit from the increased market capitalisation • Awards payables in a variable number of shares which shall not exceed the of the Company. quantity of 2,976,781 shares. • Subject to certain market conditions, among others, reaching a stock Stock Award Program and Other Share Based Payments market price for the Company shares of US$ 4.05 at vesting date. During 2008, GeoPark Shareholders voted to authorize the Board to use up • Vesting date: 31 December 2018. to 12% of the issued share capital of the Company at the relevant time for the • VCP has been classified as an equity-settled plan. purposes of the Performance-based Employee Long-Term Incentive Plan. Details of these costs and the characteristics of the different stock awards programs and other share based payments are described in the following table and explanations: 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 2016 2014 2013 2012 2011 Subtotal Stock options to Executive Directors Shares granted to Non-Executive Directors VCP 2013 VCP 2016 Executive Directors Bonus Key Management Bonus Stock awards for service contracts 1,619,105 490,000 - - - - - - - - - 82,306 - 2,191,411 - - - - - - - 70,485 - - - - 12,546 83,031 The awards that are forfeited correspond to employees that had left the Group before vesting date. 31,109 - 1,587,996 - - - - - - - - - - - - 490,000 - - - - - 70,485 - - - 82,306 12,546 - - - - - - - - - - - - 2017 865 838 - - - 2016 2015 445 821 - 855 - - 898 594 636 879 1,703 2,121 3,007 - - 2,390 454 - 1,868 - - 50 400 - 934 (325) 202 35 371 617 - 400 1,438 - 8,223 31,109 655,337 1,587,996 4,075 3,367 GeoPark 189 Note 31 Interests in Joint operations The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Chile, Colombia, Brazil and Argentina. In Chile, GeoPark is the operator in all the blocks. In Colombia, GeoPark is the operator in Llanos 34 and Yamu/Carupana blocks. In Argentina, GeoPark is the operator in CN-V block. The following amounts represent the Group’s share in the assets, liabilities and results of the joint operations which have been recognised in the Consolidated Statement of Financial Position and Statement of Income: Subsidiary / Joint operation 2017 GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Yamu/Carupana Block Llanos 34 Block Llanos 32 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 2016 GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Yamu/Carupana Block Llanos 34 Block Llanos 32 Block 10% 70% 50% 18% 18% 50% 50% 50% 60% 89.5% 45% 10% PP&E Interest E&E Assets Other Assets Total Total NET ASSETS/ Operating Assets Liabilities (LIABILITIES) Revenue (loss) profit - 55 55 (432) (377) - (48) 50% 50% 50% 60% 89.5% 45% 12.5% 9,893 17,347 9,553 4,741 131,193 835 44,167 849 6,819 1,318 568 - - - 1 4,563 209 19,126 358 347 72 169 9,893 17,347 9,553 4,742 135,756 1,044 (1,223) (233) (60) (2,993) (5,847) (492) 63,293 1,207 (11,444) (1,091) 7,166 1,390 737 (984) (232) (837) 8,670 17,114 9,493 879 (1,422) - - (150) (161) 1,749 3,072 129,909 259,815 552 1,784 (2,721) 163,917 (319) 51,849 34,238 12,731 116 6,182 1,158 (100) - 70 - - - - (1,163) (546) (474) (40) - 55 55 (424) (369) 15,108 29,718 9,920 3,418 79,811 3,819 - - - - 693 - 15,108 29,718 9,920 3,418 80,504 3,819 (93) (1) (1) 15,015 29,717 9,919 1,004 (1,988) - 5 (399) (438) (2,289) (3,943) (211) 1,129 18 76,561 125,400 3,608 2,303 (307) 83,193 1,043 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 20,945 190 GeoPark 20-F Subsidiary / Joint operation 2015 GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Llanos 17 Block Yamu/Carupana Block Llanos 34 Block Llanos 32 Block PP&E Interest E&E Assets Other Assets Total Total NET ASSETS/ Operating Assets Liabilities (LIABILITIES) Revenue (loss) profit 50% - 45 45 50% 50% 60% 14,932 27,570 8,583 36.84% - - - - - 89.5% 45% 10% 3,569 76,667 3,106 2,061 429 96 14,932 27,570 8,583 - 5,630 77,096 3,202 (2) (53) (10) (16) (93) 43 - (69) 14,879 27,560 8,567 1,810 (51,411) 13 355 (7,267) (5,661) (93) 3 (6,325) (2,235) (3,295) (213) 3,395 1,409 (16,552) 73,801 114,276 2,989 8,258 53,049 (1,343) GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field 10% 50,801 12,930 63,731 (10,395) 53,336 32,388 20,354 Capital commitments are disclosed in Note 32 (b). table A, the Group should deliver to ANH a share of the production net of Note 32 Commitments (a) 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. royalties in accordance with the following formula: Q = ((P – Po) / P) x S; where 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$/barrel) 30.22 31.39 32.56 46.50 Table A Table B WTI (P) Po < P < 2Po 2Po < P < 3Po 3Po < P < 4Po 4Po < P < 5Po 5Po < P S 30% 35% 40% 45% 50% Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties on GeoPark is obligated to make certain payments to the previous owners of Colombian production of light and medium oil are calculated on a field-by- Winchester based on the production and sale of hydrocarbons discovered field basis, using the following sliding scale: by exploration wells drilled after 25 October 2011. These payments involve Average daily production in barrels Production Royalty rate the vendor. As at the balance sheet date and based on preliminary internal an overriding royalty equal to an estimated 4% carried interest on the part of Additionally, under the terms of the Winchester Stock Purchase Agreement, Up to 5,000 5,000 to 125,000 125,000 to 400,000 400,000 to 600,000 Greater than 600,000 8% estimates of additions of 2P reserves since acquisition, the Group’s best 8% + (production - 5,000)*0.1 estimate of the total commitment over the remaining life of the concession 20% is in a range between US$ 80,000,000 and US$ 90,000,000. During 2017, 20% + (production - 400,000)*0.025 the Group has accrued and paid US$ 11,369,000 (US$ 5,414,000 in 2016 25% and US$ 7,100,000 in 2015) and US$ 9,981,000 (US$ 3,772,000 in 2016 and US$ 9,200,000 in 2015), respectively. When the API is lower than 15°, the payment is reduced to the 75% of the total calculation. 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 GeoPark 191 In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency On 22 July 2015, GeoPark signed a farm-in agreement with Wintershall for (ANP) is responsible for determining monthly minimum prices for petroleum the CN-V Block in Argentina. GeoPark will operate during the exploratory produced in concessions for purposes of royalties payable with respect phase and receive a 50% working interest in the CN-V Block in exchange for to production. Royalties generally correspond to a percentage ranging its commitment to drill two exploratory wells, for a total of US$ 10,000,000. As between 5% and 10% applied to reference prices for oil or natural gas, of the date of these Consolidated Financial Statements, GeoPark has already as established in the relevant bidding guidelines (edital de licitação) and drilled and completed one of the two committed exploratory wells for a total concession agreement. In determining the percentage of royalties applicable amount of US$ 5,455,000. to a concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. In the Manatí Chile Block, royalties are calculated at 7.5% of gas production. The remaining investment commitment for the second exploratory phase in the Flamenco Block relates to the drilling of one exploratory well to be In Argentina, crude oil production accrues royalties payable to the Province assumed 100% by GeoPark and amounts to US$ 2,100,000. On 30 June 2017, of Mendoza equivalent to 12% on estimated value at well head of those the Chilean Ministry accepted GeoPark’s proposal to extend the second products. This value is equivalent to final sales price less transport, storage and exploratory phase for an additional period of 18 months, ending on 7 May treatment costs. (b) Capital commitments Colombia 2019. The investment commitment for the first exploratory period in the Campanario and Isla Norte Blocks has already been fulfilled. The investments to be made in the second exploratory period will be assumed The VIM 3 Block minimum investment program consists of 200 sq km of 2D 100% by GeoPark. On 29 May 2017, the Chilean Ministry accepted seismic and drilling one exploratory well, with a total estimated investment GeoPark’s proposal to update the value of the commitments in both the of US$ 22,290,800 during the initial three year exploratory period ending 2 Campanario and Isla Norte Blocks as well as the guarantees related to those September 2018. commitments. Consequently, the future investment commitments assumed by GeoPark for the second exploratory period are up to: The Llanos 34 Block (45% working interest) has committed to drill two • Campanario Block: 3 exploratory wells before 10 July 2019 (US$ exploratory wells, one before 15 March 2017 and the other before 14 4,758,000) September 2019. The remaining commitment amounted to US$ 6,255,000 • Isla Norte Block: 2 exploratory wells before 7 May 2019 (US$ 2,855,000) at GeoPark’s working interest. As of the date of these Consolidated Financial Statements, GeoPark is awaiting the ANH’s approval of the wells already drilled As of 31 December 2017, the Group has established guarantees for its total that were presented as fulfilment of the commitments to be performed in the commitments. block. After this approval, the remaining commitment would amount to US$ 3,008,000. Brazil The Llanos 32 Block (12% working interest) has committed to drill one • SEAL-T-268 Block: before 15 May 2017 (US$ 230,000). On 12 May 2017, the exploratory well before 20 August 2018. The remaining commitment amounts Brazilian National Agency of Petroleum, Natural Gas and Biofuels (“ANP”) to US$ 587,500 at GeoPark’s working interest. notified the suspension of the exploratory period to fulfill the commitments in The future investment commitments assumed by GeoPark are up to: the block. Argentina • REC-T-94 Block: 2 exploratory wells before 12 July 2017 (US$ 2,300,000). On 20 August 2014, the consortium of GeoPark and Pluspetrol was awarded An exploratory well was drilled and completed in April 2017. On 12 July two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part 2017, the ANP notified the suspension of the exploratory period to fulfill the of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa commitments in the block. Mendocina de Energia S.A. (“EMESA”). The consortium consists of Pluspetrol • REC-T-93 Block: 3D seismic before 20 December 2018 (US$ 50,000). (Operator with a 72% working interest (“WI”), EMESA (Non-operated with a • REC-T-128 Block: 1 exploratory well before 20 December 2018 (US$ 10% WI) and GeoPark (Non-operated with an 18% WI). As of the date of these 2,690,000). Consolidated Financial Statements, the remaining commitments in the blocks • POT-T-747 Block: 1 exploratory well before 20 December 2018 (US$ for the first exploratory period amount to US$ 1,200,000 at GeoPark’s working 1,840,000). An exploratory well was drilled in December 2017. interest. • POT-T-882 Block: 35 sq km of 2D seismic before 20 December 2018 (US$ 480,000). • POT-T-619 Block: 1 well before 16 September 2018 (US$ 700,000). 192 GeoPark 20-F (c) Operating lease commitments – Group company as lessee The Group leases various plant and machinery under non-cancellable operating lease agreements. Investments LLP, GPK Holdings, and other investment vehicles. (c) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, The Group also leases offices under non-cancellable operating lease agreements. The lease terms are between 2 and 3 years, and most of lease agreements are renewable at the end of the lease period at market rate. credit officers, managers and legal staff. (d) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 83,716 common shares held by him personally. During 2017 a total amount of US$ 46,195,000 (US$ 47,871,000 in 2016 and US$ 16,731,000 in 2015) was charged to the income statement and US$ 34,160,000 of operating leases were capitalised as Property, plant and equipment related to rental of drilling equipment and machinery (US$ 32,058,000 in 2016 and US$ 7,102,000 in 2015). The future aggregate minimum lease payments under non-cancellable operating leases are as follows: Amounts in US$ ‘000 2017 2016 2015 Operating lease commitments Falling due within 1 year Falling due within 1 – 3 years Falling due within 3 – 5 years Falling due over 5 years 32,180 5,777 2,793 - 67,752 14,031 5,066 114 12,878 8,257 2,456 309 Total minimum lease payments 40,750 86,963 23,900 Note 33 Related parties Controlling interest The main shareholders of GeoPark Limited, a company registered in Bermuda, as of 31 December 2017, are: Shareholder James F. Park (a) Gerald E. O’Shaughnessy (b) Manchester Financial Group, LP IFC Equity Investments(c) Juan Cristóbal Pavez(d) Other shareholders Common shares 7,891,269 7,193,316 5,103,439 3,422,476 2,961,520 34,024,199 60,596,219 Percentage of outstanding common shares 13.02% 11.87% 8.42% 5.65% 4.89% 56.15% 100.00% (a) Held by Energy Holdings, LLC, which is controlled by James F. Park, a member of our Board of Directors. (b) Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP GeoPark 193 Balances outstanding and transactions with related parties Account (Amounts in ´000) Transaction in the year Balances at year end Related Party Relationship 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 2015 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 Administrative expenses - - - - 2,224 170 411 - - - - 1,587 113 371 - - - - 1,560 101 66 377 2,455 56 (31,184) (10,015) - - - 3,311 42 (27,801) (1,614) - - - 4,634 38 (21,045) (113) - - - - Joint Operations Joint Operations LGI LGI Joint Operations LGI Carlos Gulisano Pedro 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 Aylwin Partner Partner Joint Operations Partner Non-Executive Director (a) Executive Director (b) Joint Operations Joint Operations LGI LGI Joint Operations LGI Carlos Gulisano Carlos Gulisano Pedro Aylwin Partner Partner Joint Operations Partner Non-Executive Director (a) Non-Executive Director (a) Executive Director (b) (a) Corresponding to consultancy services. (b) Corresponding to wages and salaries for US$ 271,000 (US$ 246,000 in 2016 and US$ 317,000 in 2015) and bonus for US$ 140,000 (US$ 125,000 in 2016 and US$ 60,000 in 2015). There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial Statements, the normal remuneration of Board of Directors and other benefits informed in Note 11. 194 GeoPark 20-F 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 held by Trayectoria, the counterpart in the Yamú Block, operated by GeoPark, that includes a 10% economic interest in all of the Yamú fields. According to the terms of the swap operation, GeoPark had written off a receivable with 2017 726 137 212 39 1,114 2016 487 - 134 - 621 2015 Trayectoria. 557 - Following this transaction, GeoPark continued to be the operator and have 129 an 89.5% interest in the Carupana Field and 100% in Yamú and Potrillo Fields. - The Group recognised, during 2015, a loss of US$ 296,000 generated by this 686 transaction. Non-audit services fees relate to consultancy and other services for 2017. Acquisition of Tiple Block Note 35 Business transactions a. Peru Entry in Peru GeoPark executed a joint operation agreement related to certain exploration activities in a new high-potential exploration acreage (“Tiple Block Acreage”) in the Llanos Basin in Colombia, through a partnership with CEPSA Colombia S.A. (a subsidiary of CEPSA SAU, the Spanish integrated energy and petrochemical company). The Tiple Block Acreage is located adjacent to GeoPark’s Llanos 34 Block The Group has executed a Joint Investment Agreement and Joint Operating (GeoPark operated, 45% WI). This exploration area covers approximately Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an interest in 21,000 acres and has full 3D seismic coverage. and operate the Morona Block located in northern Peru. GeoPark will assume a 75% working interest (“WI”) of the Morona Block, with Petroperu retaining The agreement provides for GeoPark to drill one exploration well, which is a 25% WI. The transaction has been approved by the Board of Directors of scheduled to be drilled in the first half of 2018. The total estimated investment both Petroperu and GeoPark. The agreement was subject to Peru regulatory amounts to between US$ 7,000,000 and US$ 8,000,000 (including drilling, approval, which was completed on 1 December 2016 following the issuance of completion, civil works and other facilities). Supreme Decree 031-2016-MEM. Incremental interest in Llanos 32 Block The Morona Block, also known as Lote 64, covers an area of 1.9 million On 22 August 2017, GeoPark acquired an additional 2.5% interest in the Llanos acres on the western side of the Marañón Basin, one of the most prolific 32 Block. No gain or loss has been generated by this transaction. hydrocarbon basins in Peru. It contains the Situche Central oil field, which has been delineated by two wells (with short term tests of approximately 2,400 Zamuro Farm-in agreement and 5,200 bopd of 35-36° API oil each) and by 3D seismic. GeoPark executed a farm-in agreement to drill the Zamuro exploration prospect, which is located in the Llanos 32 block (GeoPark non-operated, In accordance with the terms of the agreement, GeoPark has committed to 12.5% WI). The farm-in agreement provides for the drilling of an exploration carry Petroperu on a work program that provides for testing and start-up well to be funded by GeoPark and, in the event of a commercial discovery, production of one of the existing wells in the field, subject to certain technical GeoPark would increase its economic interest to 56.25% in the Zamuro field and economic conditions being met. During 2017, GeoPark recognised an area. The well is scheduled to be drilled in the second half of 2018. initial consideration owed to Petroperu that could be up to US$ 10,684,000, subject to GeoPark’s review and approval of supporting documentation. This c. Argentina amount will be offset by the Petroperu’s interest in the operation expenses to be incurred by GeoPark in the block. Expected capital expenditures in Acquisition of the Aguada Baguales, El Porvenir and Puesto Touquet blocks 2018 for the Morona Block are mainly related to facility maintenance and On 18 December 2017, GeoPark executed an asset purchase agreement to environmental and engineering studies. b. Colombia Swap operation acquire 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$ 52,000,000. Closing of the transaction is subject to customary regulatory approvals, and is expected in the first quarter 2018. On 19 November 2015, the Colombian subsidiary agreed to exchange its 10% non-operating economic interest in Cerrito Block for additional interests GeoPark 195 As of the date of these Consolidated Financial Statements, GeoPark has • The future oil prices have been calculated taking into consideration the recorded the security deposit of US$ 15,600,000 granted to the seller within oil curves prices available in the market, provided by international advisory “Other financial assets” in the Consolidated Statement of Financial Position. No companies, weighted through internal estimations in accordance with price other amounts are recorded in relation with this transaction until its closing. curves used by D&M; Note 36 • Three price scenarios were projected and weighted in order to minimize misleading: low price, middle price and high price (see below table “Oil price Impairment test on Property, plant and equipment scenarios”); Oil price crisis started in the second half of 2014 and prices fell dramatically, the Group adjusted this marker price on its model valuation to reflect the WTI and Brent, the main international oil price markers, fell more than effective price applicable in each location (see Note 3 “Price risk”); 60% between October 2014 and February 2016. Because of those market • The model valuation was based on the expected cash flow approach; conditions, during 2015, the Group undertook a decisive cost cutting program • The revenues were calculated linking price curves with levels of production to ensure its ability to both maximize the work program and preserve its according to certified reserves (see below table “Oil price scenarios”); liquidity. The main decisions included: • The levels of production have been linked to certified risked 1P, 2P and 3P • The table “Oil price scenarios” was based on Brent future price estimations; reserves (see Note 4); – Reduction of its capital investment taking advantage of the discretionary • Production and structure costs were estimated considering internal work program. historical data according to GeoPark’s own records and aligned to 2018 – Deferment of capital projects by regulatory authority and partner approved budget; agreement. • The capital expenditures were estimated considering the drilling campaign – Renegotiation and reduction of oil and gas service contracts, including necessary to develop the certified reserves; drilling and civil work contractors, as well as transportation trucking and • The assets subject to impairment test are the ones classified as Oil and Gas pipeline costs. properties and Production facilities and machinery; – Operating cost improved efficiencies and temporary suspension of certain • The carrying amount subject to impairment test includes mineral interest, marginal producing oil and gas fields. if any; • The income tax charges have considered future changes in the applicable During February 2015, the Group reduced its workforce significantly. This income tax rates (see Note 16). reduction streamlined certain internal functions and departments for creating a more efficient workforce in the current economic environment. Table Oil price scenarios (a): As a result, the Group achieved cost savings associated with the reduction of full-time and temporary employees, excluding one-time termination costs. Continuous efforts and actions to reduce costs and preserve liquidity have continued since. As a result of the situation described, the Group recognised an impairment loss of US$ 149,574,000 in 2015 after evaluating the recoverability of its fixed assets affected by oil price drop, as such situation constitutes an impairment Year 2018 2019 2020 indicator according to IAS 36 and, consequently, it triggers the need of Over 2021 assessing fair value of the assets involved against their carrying amount. Amounts in US$ per Bbl. Low price Middle price High price (15%) (60%) (25%) 64.9 53.2 54.4 54.3 64.9 62.5 63.9 63.7 64.9 71.7 73.4 73.2 The Management of the Group considers as Cash Generating Unit (CGU) each of the blocks in which the Group has working or economic interests. The (a) The percentages indicated between brackets represent the Company estimation regarding each price scenario. blocks with no material investment on fixed assets or with operations that are As a consequence of the evaluation no additional impairment loss was not linked to oil prices were not subject to impairment test. recognised in 2017. In 2016, part of the impairment recorded in Colombia was reversed for an amount of US$ 5,664,000 due to increase in estimated market During 2016 and 2017 the impairment tests were reviewed. The main prices and improvements in cost structure. assumptions taken into account for the impairment tests for the blocks below mentioned were: 196 GeoPark 20-F Note 37 Supplemental information on oil and gas activities (unaudited). The following information is presented in accordance with ASC No. 932 “Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published on 31 December 2008. This information includes the Group’s oil and gas production activities carried out in Chile, Colombia, Brazil, Argentina and Peru. Table 1 - Costs incurred in exploration, property acquisitions and development (a) The following table presents those costs capitalised as well as expensed that were incurred during each of the years ended as of 31 December 2017, 2016 and 2015. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves. 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 Chile Colombia Argentina Brazil Perú Total - - - - - - 3,283 10,231 13,514 37,017 49,268 86,285 - - - 8,080 167 8,247 Chile Colombia Argentina - - - - 5,519 4,566 10,085 15,233 12,500 27,733 - - 1,894 - 1,894 - - - 5,207 1,210 6,417 Brazil - - 2,555 191 2,746 - - - - - - 743 14,074 14,817 Perú 54,330 74,950 129,280 Total - - - - - - - 25,201 17,257 42,458 GeoPark 197 Amounts in US$ ‘000 Year ended 31 December 2015 Acquisition of properties Proved Unproved Total property acquisition Exploration Development Total costs incurred Chile Colombia Argentina Brazil Perú Total - - - - 3,598 13,315 16,913 14,845 14,752 29,597 - - 1,103 56 1,159 - - 2,562 3,780 6,342 - - - - - - - 22,108 31,903 54,011 (a) Includes capitalised amounts related to asset retirement obligations. Table 2 - Capitalised costs related to oil and gas producing activities The following table presents the capitalised costs as at 31 December 2017, 2016 and 2015, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates. 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 capitalised costs Accumulated depreciation Total net capitalised costs (a) Includes capitalised amounts related to asset retirement obligations. (b) Do not include Peru capitalised 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 capitalised costs Accumulated depreciation Total net capitalised costs Chile Colombia Argentina Brazil Total 80,611 397,031 12,508 49,702 69,906 291,050 11,290 4,106 539,852 376,352 (253,764) (228,793) 286,088 147,559 843 11,159 48 2,975 15,025 (5,700) 9,325 6,036 77,264 70 7,585 157,396 776,504 23,916 64,368 90,955 1,022,184 (39,509) (527,766) 51,446 494,418 Chile Colombia Argentina Brazil Total 80,611 380,037 18,274 48,908 46,785 230,100 12,534 4,503 527,830 293,922 (230,917) (190,025) 296,913 103,897 843 4,849 36 1,894 7,622 (5,692) 1,930 4,174 77,255 2,082 6,468 132,413 692,241 32,926 61,773 89,979 919,353 (29,803) (456,437) 60,176 462,916 (a) Includes capitalised amounts related to asset retirement obligations and impairment loss reversal in Colombia for US$ 5,664,000. 198 GeoPark 20-F Amounts in US$ ‘000 At 31 December 2015 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects Unproved properties Gross capitalised costs Accumulated depreciation Total net capitalised costs Chile Colombia Argentina Brazil Total 79,040 367,722 21,830 70,062 42,852 213,480 7,703 8,180 538,654 272,215 (201,138) (160,759) 337,516 111,456 843 4,849 290 - 5,982 (5,654) 328 2,097 62,941 - 8,758 124,832 648,992 29,823 87,000 73,796 890,647 (14,236) (381,787) 59,560 508,860 (a) Includes capitalised amounts related to asset retirement obligations and impairment loss in Chile and Colombia for US$ 104,515,000 and US$ 45,059,000, respectively. 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 2017, 2016 and 2015. Income tax for the years presented was calculated utilizing the statutory tax rates. 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) 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 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 Chile Colombia Argentina Brazil Total 32,738 263,076 70 34,238 330,122 (19,685) (1,314) (42,677) (24,236) (20,999) (66,913) (1,404) (994) - (22,705) (13,364) 2,005 (11,359) (3,856) (683) - (38,721) 152,903 (61,161) 91,742 (7,603) (3,134) (70,290) (28,697) (10,737) (98,987) (325) (13) (338) (707) - - (3,985) (930) - (8) (10,659) (983) 344 (639) 7,927 (2,695) 5,232 (9,952) (2,607) - (72,093) 146,483 (61,507) 84,976 Chile Colombia Argentina Brazil Total 36,723 126,228 (20,674) (1,495) (29,326) (7,281) (22,169) (36,607) (21,060) (11,690) (897) - (29,890) (37,293) 5,594 (31,699) (459) 5,664 (29,439) 53,697 (21,479) 32,218 - - - - - - - - - - - 29,719 192,670 (5,738) (2,721) (55,738) (11,497) (8,459) (67,235) (5,636) (1,198) - (12,785) 1,641 (558) 1,083 (38,386) (2,554) 5,664 (72,114) 18,045 (16,443) 1,602 GeoPark 199 Amounts in US$ ‘000 Year ended 31 December 2015 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 expense Results of oil and gas operations (a) Do not include Peru costs. (b) Represents accretion of ARO liability. Table 4 - Reserve quantity information Estimated oil and gas reserves Chile Colombia Argentina Brazil Total 44,808 131,897 597 32,388 209,690 (26,731) (1,973) (40,384) (8,150) (28,704) (48,534) (30,499) (789) (104,515) (37,664) (7,132) (890) (45,059) (50,675) (1,414) (34) (1,448) (1,159) - - (5,058) (2,998) (8,056) (1,103) (896) (73,587) (13,155) (86,742) (39,893) (2,575) - (149,574) (91) (13,401) (101,831) (157,363) (20,393) (2,101) 8,932 (170,925) 23,604 7,953 735 (3,037) 29,255 (133,759) (12,440) (1,366) 5,895 (141,670) Proved reserves represent estimated quantities of oil (including crude Reserves engineering is a subjective process of estimation of hydrocarbon oil and condensate) and natural gas, which available geological and accumulation, which cannot be accurately measured, and the reserve engineering data demonstrates with reasonable certainty to be recoverable estimation depends on the quality of available information and the in the future from known reservoirs under existing economic and operating interpretation and judgment of the engineers and geologists. Therefore, conditions. Proved developed reserves are proved reserves that can the reserves estimations, as well as future production profiles, are often reasonably be expected to be recovered through existing wells with existing different than the quantities of hydrocarbons which are finally recovered. equipment and operating methods. The choice of method or combination The accuracy of such estimations depends, in general, on the assumptions of methods employed in the analysis of each reservoir was determined on which they are based. by the stage of development, quality and reliability of basic data, and production history. The estimated GeoPark net proved reserves for the properties evaluated as of 31 December 2017, 2016 and 2015 are summarised as follows, expressed The Group believes that its estimates of remaining proved recoverable in thousands of barrels (Mbbl) and millions of cubic feet (MMcf ): oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The Group estimates its reserves at least once a year. The Group’s reserves estimation as of 31 December 2017, 2016 and 2015 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton prepared its proved oil and natural gas reserve estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by the SEC, and in accordance with the oil and gas reserves disclosure provisions of ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities). 200 GeoPark 20-F As of 31 December 2017 As of 31 December 2016 As of 31 December 2015 Oil and Oil and Oil and condensate Natural gas condensate Natural gas condensate Natural gas (Mbbl) (MMcf ) (Mbbl) (MMcf ) (Mbbl) (MMcf ) 720.0 21,101.0 76.0 9,502.0 31,399.0 3,423.0 44,398.0 - 9,215.0 57,036.0 88,435.0 8,688.0 - 23,821.0 - 32,509.0 11,329.0 - - - 11,329.0 43,838.0 547.0 9,502.0 72.0 9,316.0 6,610.0 - 29,525.0 - 19,437.0 36,135.0 6,052 27,838.0 - 9,305.0 43,195.0 62,632.0 29,690.0 - - - 29,690.0 65,825.0 498.0 8,177.8 120.0 - 8,795.8 5,455.8 22,245.5 - - 27,701.3 36,497.1 4,922.0 - 36,158 - 41,080.0 31,593.0 - - - 31.593.0 76,673.0 Net proved developed Chile (a) Colombia (b) Brazil (c) Peru (d) Total consolidated Net proved undeveloped Chile (e) Colombia (f ) Brazil (c) Peru (d) Total consolidated Total proved reserves (a) Fell Block accounts for 98% of the reserves (99% in 2016 and 91% in 2015) (LGI owns a 20% interest) and Flamenco Block accounts for 2% (1% in 2016 and 9% in 2015) (LGI owns 31.2% interest). (b) Llanos 34 Block, Cuerva Block and Yamu Block account for 98%, 1% and 1% (Llanos 34 Block and Llanos 32 Block account for 99% and 1% in 2016, and Llanos 34 Block and Cuerva Block account for 94% and 3% in 2015) of the proved developed reserves, respectively (LGI owns a 20% interest). (c) BCAM-40 Block accounts for 100% of the reserves. (d) Morona Block accounts for 100% of the reserves. (e) Fell Block accounts for 97% of the reserves (99% in 2016 and 100% in 2015) (LGI owns a 20% interest), Flamenco Block accounts for 3% in 2017 (1% in 2016 and nil in 2015) (LGI owns 31.2% interest). (f ) Llanos 34, Cuerva Block and Yamu Block account for 97%, 2% and 1% (Llanos 34 Block accounts for 100% in 2016 and Llanos 34 Block and Cuerva Block account for 95% and 4% in 2015) of the proved undeveloped reserves, respectively (LGI owns a 20% interest). The amounts of proved reserves disclosed herein as of 31 December 2017 include 13,934.1 thousand barrels of crude oil condensate (8,796.2 in 2016 and 7,281.3 in 2015) and natural gas liquids and 4,101.5 million cubic feet of natural gas (7,356.0 in 2016 and 7,345.8 in 2015) corresponding to non- controlling interest held by LGI. GeoPark 201 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 2014 Increase (decrease) attributable to: Revisions (a) Extensions and discoveries (b) Production Reserves as of 31 December 2015 Increase (decrease) attributable to: Revisions (c) Extensions and discoveries (d) Purchases of minerals in place (e) Production Reserves as of 31 December 2016 Increase (decrease) attributable to: Revisions (f ) Extensions and discoveries (g) Production Reserves as of 31 December 2017 Chile Colombia 6,441.9 24,735.3 119.0 100.0 (707.1) (225.0) 10,489.0 (4,576.0) 5,953.8 30,423.3 1,148.0 - - 5,779.0 6,311.0 - (502.8) (5,173.3) 6,599.0 37,340.0 (2,109.0) - (347.0) 6,315.0 29,047.0 (7,203.0) 4,143.0 65,499.0 Brazil 130.0 7.6 - (17.6) 120.0 (34.0) - - (14.0) 72.0 19.0 - (15.0) 76.0 Peru Total - - - - - - - 31,307.2 (98.4) 10,589.0 (5,300.7) 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 (a) For the year ended 31 December 2015, the Group’s oil and condensate proved reserves were revised downwards by 0.1 mmbbl. The primary factors (e) In December 2016, we obtained final regulatory approval for our acquisition of the Morona Block in Peru. The Joint Investment and Operating Agreement leading to the above were: dated 1 October 2014 and its amendments were closed on 1 December 2016 - The impact of lower average oil prices resulting in a 2 mmbbl decrease in reserves from the La Cuerva and Yamu blocks in Colombia, and a 1 mmbbl decrease in reserves related to a change in a previously adopted development following the issuance of Supreme Decree 031-2016-MEM.XXX. (f ) 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 plan in the Fell Block in Chile. leading to the above were: - Such decrease was partially offset by better than expected performance from - Better than expected performance from existing wells, from the Tigana and existing wells, of which 2 mmbbl was from the Llanos 34 Block in Colombia Jacana fields in the Llanos 34 Block, resulting in an increase of 3.8 mmbbl. and 1 mmbbl from the Fell Block in Chile. (b) In Colombia, the extensions and discoveries are primarily due to the Tilo, Jacana, and Chachalaca field discoveries in the Llanos 34 Block. (c) 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 - 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 a change in a previously adopted development plan in the Fell Block in Chile, resulting in a 2.4 mmbbl decrease. (g) In Colombia, the extensions and discoveries are primary due to the Chiricoca, Jacamar, and Curucucu field discoveries in the Llanos 34 Block and minor fields in the Llanos 34 Block, and 1 mmbbl was from the Fell Block in the Tigana and Jacana field extentions in the Llanos 34 Block. Chile. - Such increase was partially offset by lower average oil prices impacting the La Cuerva and Yamu blocks in Colombia, resulting in a 2 mmbbl decrease. (d) In Colombia, the extensions and discoveries are primarily due to the Jacana field appraisal wells in the Llanos 34 Block. 202 GeoPark 20-F Net proved reserves (developed and undeveloped) of natural gas: (e) In Chile, the extensions and discoveries are primary due to the Uaken Field discovery in the Fell Block. Millions of cubic feet Chile Brazil Total Reserves as of 31 December 2014 33,970.0 40,464.0 74,434.0 Revisions refer to changes in interpretation of discovered accumulations and Increase (decrease) attributable to: Revisions (a) Extensions and discoveries (b) Production (2,807.6) 9,378.0 2,907.0 99.4 development plan of certain fields under appraisal and development phases. some technical and logistical needs in the area obliged to modify the timing and - 9,378.0 (4,025.4) (7,213.0) (11,238.4) Table 6 - Standardized measure of discounted future net cash flows related to Reserves as of 31 December 2015 36,515.0 36,158.0 72,673.0 proved oil and gas reserves Increase (decrease) attributable to: Revisions (c) Production 5,078.0 (319.0) 4,759.0 The following table discloses estimated future net cash flows from future (5,293.0) (6,314.0) (11,607.0) production of proved developed and undeveloped reserves of crude oil, Reserves as of 31 December 2016 36,300.0 29,525.0 65,825.0 condensate and natural gas. As prescribed by SEC Modernization of Oil Increase (decrease) attributable to: Revisions (d) Extensions and discoveries (e) Production and Gas Reporting rules and ASC 932 of the FASB Accounting Standards (13,725.0) 1,187.0 59.0 (13,666.0) Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly - 1,187.0 SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future (3,745.0) (5,763.0) (9,508.0) net cash flows were estimated using the average first day-of-the-month Reserves as of 31 December 2017 20,017.0 23,821.0 43,838.0 price during the 12-month period for 2017, 2016 and 2015 and using a 10% (a) For the year ended 31 December 2015, the Group’s proved natural gas reserves were revised by 0.1 billion cubic feet. This was the combined effect of: annual discount factor. Future development and abandonment costs include estimated drilling costs, development and exploitation installations and abandonment costs. These future development costs were estimated based on evaluations made by the Group. The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which - Better than expected performance from existing wells that resulted in an we have interests, as of the date this supplementary information was filed. increase of 13 billion cubic feet (3 billion cubic feet from the Manati field in Brazil and 10 billion cubic feet from the Fell Block in Chile). This standardized measure is not intended to be and should not be - The above was partially offset by a decrease of 13 billion cubic feet due to interpreted as an estimate of the market value of the Group’s reserves. The lower average gas prices in the Fell and Tierra del Fuego (TdF) blocks in Chile purpose of this information is to give standardized data to help the users of (totalling 3 billion cubic feet) and changes in previously adopted development the financial statements to compare different companies and make certain plan in the Fell Block in Chile (totalling 10 billion cubic feet). (b) In Chile, the extensions and discoveries are primary due to the Ache Field discovery and from the extension well in the Fell Block. (c) 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 projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money driven by better than expected performance from existing wells, primarily the over the lapse of time and of the risks inherent to the production of oil and Ache field in the Fell Block in Chile, resulting in an addition of 9 billion cubic gas. These future changes may have a significant impact on the future net feet. This increase was partially offset by a reduction of 4 billion cubic feet in cash flows disclosed below. For all these reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows derived from the reserves of hydrocarbons. the Pampa Larga field, also in the Fell Block. (d) 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 combined effect of: - Removal of proved undeveloped reserves due to changes in previously adopted development plan in the Fell Block in Chile and unsuccessful proved undeveloped executions in the Fell Block in Chile (totalling 21.3 billion cubic feet). - The above was partially offset by an increase of 6.8 billion cubic feet due 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 increase of 0.8 billion cubic feet. GeoPark 203 Amounts in US$ ‘000 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 At 31 December 2015 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 Chile Colombia Brazil Peru Total 284,711 2,434,954 157,527 1,047,540 3,924,732 (131,788) (531,751) (56,311) (466,110) (1,185,960) (57,690) (187,414) (7,524) (235,920) (488,548) (656) (558,226) (10,442) (107,294) (676,618) 94,577 1,157,563 83,250 238,216 1,573,606 (19,338) (343,561) (13,293) (147,682) (523,874) 75,239 814,002 69,957 90,534 1,049,732 394,993 873,771 (186,700) (229,593) (149,785) (69,996) (8,344) 50,164 (191,096) 383,086 200,713 (74,116) (16,352) (21,041) 89,204 941,463 2,410,940 (497,187) (987,596) (234,328) (470,461) (69,698) (290,179) 140,250 662,704 (14,709) (113,584) (15,688) (109,321) (253,302) 35,455 269,502 73,516 30,929 409,402 403,199 1,032,339 (186,933) (309,394) (112,312) (99,305) (17,904) (195,957) 86,050 427,683 (17,895) (127,586) 68,155 300,097 221,206 (99,832) (16,360) (16,837) 88,177 (15,861) 72,316 - - - - - - - 1,656,744 (596,159) (227,977) (230,698) 601,910 (161,342) 440,568 204 GeoPark 20-F 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 2014 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 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 Purchase of Minerals in place Net changes in income taxes Accretion of discount Present value at 31 December 2017 The amounts of the standardized measure of discounted future net cash flows herein for the year ended 31 December 2017, 2016 and 2015 include $178.1 million, $61.4 million and $73.9 million that correspond to the non-controlling interest held by LGI. Chile Colombia 227,658 (20,948) 584,071 (97,152) (256,828) (547,379) 28,227 23,595 15,093 (5,463) 28,611 28,210 68,155 (15,127) (16,854) (49,763) - 9,417 22,765 - 8,256 8,606 (20,123) 174,951 29,965 (14,528) 101,576 88,716 300,097 (91,163) (171,131) 14,941 76,641 17,302 70,180 - 3,030 49,605 35,455 269,502 (14,251) (198,631) 26,928 79,078 - 7,146 289,199 (124,053) 49,574 67,571 Brazil 112,145 (37,428) (27,404) 542 - 4,872 4,845 1,573 13,171 72,316 (20,945) 16,366 542 - 2,214 (1,872) (4,020) 8,915 73,516 (26,979) (3,000) 8,385 - - Peru Total - - - - - - - - - - - - - - - - - - 923,874 (155,528) (831,611) 8,646 198,546 49,930 (15,146) 131,760 130,097 440,568 (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 - 30,929 (69,594) 673,622 603 1,133 605,764 6,097 4,380 (258,842) 46,060 7,976 9,456 (11,828) (256,597) 10,063 69,959 75,239 814,002 69,957 90,534 1,049,732 GeoPark 205 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, 2018 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 and for the company and have: 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, to ensure that material information relating to the company, including its d. Disclosed in this report any change in the company’s internal control over consolidated subsidiaries, is made known to us by others within those entities, financial reporting that occurred during the period covered by the annual particularly during the period in which this report is being prepared; report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 5. The company’s other certifying officer(s) and I have disclosed, based on to provide reasonable assurance regarding the reliability of financial our most recent evaluation of internal control over financial reporting, to reporting and the preparation of financial statements for external purposes in the company’s auditors and the audit committee of the company’s board of accordance with generally accepted accounting principles; directors (or persons performing the equivalent functions): 206 GeoPark 20-F Exhibit 12.2 c. Evaluated the effectiveness of the company’s disclosure controls and Certification by the Principal Executive Officer Pursuant to 18 U.s.c. 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, 2017 (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 1. the Report fully complies with the requirements of Section 13(a) or 15(d) of 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 the company’s auditors and the audit committee of the company’s board of 2. the information contained in the Report fairly presents, in all material directors (or persons performing the equivalent functions): respects, the financial condition and results of operations of the Company. a. All significant deficiencies and material weaknesses in the design or Date: April 11, 2018 operation of internal control over financial reporting which are reasonably Andrés Ocampo likely to adversely affect the company’s ability to record, process, summarize Chief Financial Officer and report financial information; and (Principal Financial Officer) 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, 2017 (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, 2018 James F. Park Chief Executive Officer (Principal Executive Officer) GeoPark 207 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 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 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. 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). 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. 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. 208 Annual Report 2017 / Board of Directors CORPORATE MANAGEMENT TEAM JAMES F. PARK Chief Executive Officer ALBERTO MATAMOROS Argentina, Chile AUGUSTO ZUBILLAGA Chief Operating Officer ANDRÉS OCAMPO Chief Financial Officer PEDRO E. AYLWIN Legal & Governance BARBARA BRUCE Peru LIVIA VALVERDE Brazil SALVADOR MINNITI Exploration MARCELA VACA Colombia CARLOS MURUT Reserves & Development JUAN CARLOS FERRERO Operations HORACIO FONTANA Drilling & Workover AGUSTINA WISKY Capacities GUILLERMO PORTNOI New Business STACY STEIMEL Shareholder Value SECRETARY & ADVISORS Registered Office Corporate Offices Cumberland House 9th floor, 1 Victoria Street Hamilton HM11 - Bermuda Buenos Aires Office Florida 981 – 1st floor C1005AAS Buenos Aires Argentina | + 54 11 4312 9400 Santiago Office Nuestra Señora de los Ángeles 176 Las Condes, Santiago Chile | + 56 2 242 9600 Bogota Office Street 94 N° 11-30, 8th floor Bogota Colombia | +57 1 743 2337 Corporate Secretary Pedro E. Aylwin Counsel to the Company Davis Polk & Wardwell LLP as to New York Law Solicitors to the Company as to Bermuda Law Independent Auditors 450 Lexington Avenue New York, NY 10017 USA Cox Hallett Wilkinson Cumberland House 9th floor, 1 Victoria Street Hamilton HM11 - Bermuda P.O. Box HM 1561 Hamilton HMFX - Bermuda Price Waterhouse & Co. S.R.L. Bouchard 557, 8th floor Buenos Aires Argentina Petroleum Consultant DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 USA Registrar Computershare Investor Services Queensway House 480 Washington Blvd. Jersey City, NJ 07310 GeoPark 209 ANNUAL REPORT 2017 WWW.GEO-PARK.COM

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