Geopark Ltd
Annual Report 2015

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ANNUAL REPORT 2015 5 1 0 2 T R O P E R L A U N N A k r a P o e G ANNUAL REPORT 2015 WWW.GEO-PARK.COM EXPLORER OPERATOR CONSOLIDATOR CONTENTS DIRECTORS, SECRETARy & ADVISORS 4 13 18 20 22 24 Letter to Shareholders Business Approach and Guidelines 2015 Performance Our Strengths Our Approach Our Value System 27 Form 20-F 172 Consolidated Financial Statements 228 229 Board of Directors Directors, Secretary & Advisors Directors Gerald Eugene O’Shaughnessy (Chairman) James Franklin Park (Chief Executive Officer and Deputy Chairman) Peter Ryalls (Non-Executive Director) Juan Cristóbal Pavez (Non-Executive Director) Carlos Gulisano (Non-Executive Director) Bob Bedingfield (Non-Executive Director) Pedro Aylwin (Executive Director) Registered Office 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 Pedro Aylwin Corporate Offices Director of Legal and Governance and Corporate Secretary Counsel to the Company Davis Polk & Wardwell LLP as to New York Law 450 Lexington Avenue New york, Ny 10017 USA Solicitors to the Company Cox Hallett Wilkinson as to Bermuda Law Cumberland House 9th Floor, 1 Victoria Street Hamilton HM11 - Bermuda P.O. Box HM 1561 Hamilton HMFX - Bermuda Independent Auditors Price Waterhouse & Co. S.R.L. Bouchard 557, Floor 8 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 BOTTOM LINE Oil and Gas Production 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 2010 2011 2012 2013 2014 2015 Oil Gas Oil and Gas Reserves 120 90 60 30 e o b M M 0 2010 2011 2012 2013 2014 2015 2015 (Including Peru) Oil Gas “As an entrepreneurial and battle-tested company that has grown from scratch into one of Latin America’s leading independents, our experience and resilience were proved once again. We opportunely used this downturn to beat down costs, wring out inefficiencies, improve the organization, innovate, increase flexibility, re-prioritize the portfolio and permanently adapt to thrive in a world of lower oil prices.” 2 Annual Report 2015 GeoPark 3 LETTER TO SHAREHOLDERS Dear Fellow Shareholders: Our entire industry was whipsawed in 2015 by the oil price collapse innovation, meaningful reductions were realized in production and causing a disruption of upstream oil and gas projects around the globe. operating costs (down 34%), cash costs per boe (down 38%), G&A But GeoPark was ready. As an entrepreneurial and battle-tested (down 25%). All resulting in 85% of our production now being cash company that has grown from scratch into one of Latin America’s flow positive at oil prices of $25-30 per barrel – demonstrating leading independents, our experience and resilience were proved the profitability and quality of our assets even in a very low oil (down 18%), capital expenditures (down 79%), and drilling costs once again. We opportunely used this downturn to beat down costs, price environment. wring out inefficiencies, improve the organization, innovate, increase flexibility, re-prioritize the portfolio and permanently adapt to thrive in a world of lower oil prices. Business Platform Our conservative long term approach in building GeoPark provided Latin America has an immense hydrocarbon resource base, the underlying foundation and necessary tools. Our high quality welcoming business environment, and relatively few independent assets, risk-balanced platform across the region, financial stability, and players today. GeoPark’s vision is to capture this big opportunity capital allocation agility, coupled with the experience of our team, and grow across the region, led by a technical approach. We identify created a path forward through the turbulence to keep us on our high value proven hydrocarbon basins – based on geological, continuous ten year growth track record. infrastructure and regulatory factors – and then work to establish long term strategic positions in the targeted regions. In an environment where oil prices dropped by more than 60%, revenues declined by 51%, and new investment was reduced by Our systematic expansion to date has resulted in building stable nearly 80% (with 7 wells vs 53 wells drilled), we are proud to have and growing businesses in Colombia, Chile, Brazil, Argentina and completed 2015 with: Peru; each managed by reputable and capable local teams, with • increased oil and gas production to 23,062 boepd in the fourth supporting production and cash flows, attractive underlying quarter (annual average of approximately 20,400 boepd), reserves and resources, and inventories of new project opportunities. • increased proven oil and gas reserves to 71.1 million boe (up 13%), Our unique self-funding platform now consists of 35 hydrocarbon • increased proven and probable (2P) oil and gas reserves to 125 blocks covering 6 million acres in 12 proven hydrocarbon basins million boe (up 3%), in 5 countries, with a rich and balanced mix of production, • increased oil and gas exploration resources to 800 million to development, exploration and unconventional resource projects. 1.5 billion boe, • increased development and exploration acreage with 5 new Our independent country businesses are further enhanced by being hydrocarbon blocks, tied together by an overall corporate organization, which improves • strengthened balance sheet with $220 million in cash and credit efficiencies, reduces costs with operational and financial synergies, facilities ($83 million in cash), controls quality, pushes performance, and more effectively grows • new off-take and prepayment facility of up to $100 million to our overall company by allocating capital to the best shareholder improve crude oil sales netbacks and expand our cash cushion, and value-adding projects. • independently certified Net Present Value (NPV) of proven and probable oil and gas reserves of $1.6 billion. Our in-house SPEED value system provides the critical success ingredient by creating positive interdependence with the In the new lower oil price world, operating efficiency is the communities where we operate and ensuring safe and differentiator – and, by attacking every line item, we successfully environmentally-clean operational performance with the goal drove costs down. Through both efficiency improvements and of making us the preferred partner, employer and neighbor. 4 Annual Report 2015 / Letter to Shareholders GeoPark 5 Briefly looking at each of our businesses: Colombia Business Chile Business GeoPark is currently leading the strongest growth story in Colombia. GeoPark first proved our business model in Chile where we In less than four years we have discovered 9 new oil fields – pioneering became Chile’s first private oil and gas producer. From a ‘flat-footed’ a new geological play-type for the Llanos Basin – and increased start-up in 2006, we built a solid business with current production production from 2,500 bopd to nearly 33,000 bopd gross (15,000 of approximately 4,000 boepd, 2P reserves of 42 million boe and bopd net to GeoPark) today. During the 2015 slowdown, we still 6 blocks with approximately 1 million prospective acres, consisting grew our Colombian 2P reserves by 20% to 46.5 million boe and of approximately 320-770 million boe of exploration and our exploration resources to approximately 30-40 million boe. unconventional resources. The Llanos 34 Block, operated by GeoPark, continued to build value No new wells were drilled in 2015 in Chile as we focused on in 2015 with the Tilo, Chachalaca and Jacana new oilfield discoveries. improving the efficiency of our operation and re-balancing our The Tigana oil field (discovered in 2013) contains gross certified 3P production mix by increasing gas supply with the construction oil reserves of 66 million boe with the opportunity for approximately of treatment facilities to produce the Ache gas field in the Fell Block. 30 additional wells to fully develop the field. The Llanos 34 Block contains highly-attractive low risk, low cost and high netback fields which provide a profitable production base during periods of oil price volatility and the engine for secure future growth. Current operating costs are only $3-5 per barrel and, even in a $40 per barrel oil price environment, the drilling of new wells can provide 100% IRRs with less than 12 month paybacks. 6 Annual Report 2015 / Letter to Shareholders Brazil Business Argentina Business Our Brazil business represents a strategic base with a fully Our team has strong technical and operational experience and developed secure cash flow producing asset (a non-operated a proven track record in Argentina. We believe the country has an interest in the Manati field, Brazil’s largest producing gas field, attractive subsurface potential and we are actively working operated by Petrobras) and 13 exploration blocks in onshore to expand our asset base. mature proven hydrocarbon basins (Potiguar, Reconcavo, and Sergipe Alagoas). Estimated exploration resources for our Brazilian In 2015, we acquired a working interest in a high potential low risk asset base are approximately 70-130 million boe. exploration block in the prolific Neuquen Basin in a partnership In 2015, a new compression plant was installed at the Manati cost large shallow oil play exploration blocks previously acquired field to fully develop the discovered gas reserves and extend in the Neuquen Basin in partnership with Pluspetrol. Estimated the life of the field. On our blocks in the Reconcavo and Potiguar exploration resources for our Argentina asset base are approximately with Wintershall. This new project is a good complement to two low Basins, following seismic interpretation, our team delineated 30-50 million boe. oil prospects for future drilling. GeoPark 7 8 Annual Report 2015 / Letter to Shareholders Peru Business GeoPark positioned itself in the hydrocarbon rich Marañón Basin in Do More for Less: Aggressively reduce each and every cost – both Peru with an operating interest in the Morona Block from Petroperu internal and external – including the shut-in of underperforming assets. in its return to the upstream business. Morona is a large block, containing the discovered Situche Central oil field (two tested wells Innovate: Use our science and engineering know-how to create new and certified gross 3P of 83 million barrels), with the opportunity approaches and opportunities above and below ground. for near term cash flow, and a big upside exploration potential (approximately 320-500 million boe) with several high impact plays Stay Agile and Flexible: Continuous monitoring and adjustment of and prospects. work programs – up or down – working within our large and ready inventory of organic projects. Morona represents an important acquisition and strategic fit for GeoPark that significantly increases our overall inventory of reserves Build for Long Term: Protect critical assets, tools and capabilities and exploration resources and can contribute to our long term steady necessary for long term success and stay in hunt for new projects growth. GeoPark has designed a phased work program that permits and value dislocation opportunities. a step-by-step development to put the Situche Central field into production initially through a long-term test to begin generating In 2015, we carried out a $50 million investment program (down cash flow. The transaction is subject to Peruvian regulatory approval. from $240 million in 2014) that was funded by our own cash flows. Outlook For 2016, we designed and built a modular and flexible work and investment program based on oil prices from $25 to $50 per barrel. The base case, at a $35-40 oil price, is cash flow neutral with a $45-55 million investment plan and targets 10-15% production growth. Our plan going forward in 2016 represents a balance between cash preservation and cash generation with an emphasis on flexibility An effective tool which GeoPark has developed to manage its five and new opportunities. In times of volatility, we believe the ability to country portfolio is its capital allocation methodology. This system rapidly adapt, create and seize opportunities is preferable to a single provides the opportunity to review and select from a wide range static plan. Key principles of our program include: of projects generated by each business unit team with different Conservative Approach: Protect balance sheet and preserve cash by and it ensures that our capital always will be directed to our top reducing, deferring and renegotiating work programs – and match value-adding projects after ranking them on technical, strategic work and investment programs with forecasted cash flows. and economic criteria. It also provides greater comfort in volatile returns, potentials, risks, sizes, timelines and geographies – Capital Allocation Discipline: Selectively allocate capital to and prioritize on oil prices and project performance – and to fine-tune our lower-risk, higher netback and quicker cash flow generating projects. desired risk exposure. markets by allowing us to easily add or subtract projects depending GeoPark 9 New Projects and Countries In parallel with our conservative operating approach through the Our thanks to our Board of Directors for your continuous efforts lower oil price environment, we remain on the offensive to acquire in helping GeoPark improve and grow. In addition to significant attractively-valued new oil and gas upstream opportunities in Latin corporate governance responsibilities, GeoPark’s Board members America. National and major oil companies, which control the biggest spend substantial time working directly with our teams, sharing their and best hydrocarbon acreage, are being forced by the lower oil price experience, and traveling to our different operations. environment to reevaluate their portfolios and initiate divestment programs. Our regional platform and reputation give us first mover And, our thanks and appreciation to our investors – long term advantage in potentially acquiring these attractive projects. and new – who have joined us, believed in our project, and supported our mission. We continuously are increasing our efforts We are also making progress in establishing a new platform in to talk with you, as well as, share our story with the wider Mexico, where regulatory reforms have opened the door for private investment community. As always, your comments and companies to access Mexico’s highly attractive hydrocarbon recommendations are welcome and appreciated. We invite you assets – many of which are an excellent fit for GeoPark’s skill set. to visit us in the field or at any of our offices to know us better In 2015 we formed a partnership with the Mexican conglomerate, and learn first-hand how we work. Grupo Alfa, and participated in the hydrocarbon block bid round, however, no blocks were awarded. We look forward to delivering and reporting to you on our results in 2016. Thank You Sincerely, More than ever, we wish to recognize and thank the men and women in GeoPark for again showing your heart and professionalism by successfully managing us through 2015 and keeping us on our steady growth path forward. This was possible because of the team you have Gerald E. O’Shaughnessy built together and your trust of each other. We all continue to gain Chairman confidence for our future, knowing what we have been able to repeatedly achieve together over our history. Our team has created an enduring culture in GeoPark, which has become our most important asset and the catalyst behind our proud record of safe, clean, neighborly, transparent and successful operations. Our gratitude extends to our relentlessly supportive families who have all contributed immensely to who we have become and what we will do next. James F. Park Chief Executive Officer 10 Annual Report 2015 / Letter to Shareholders GeoPark 11 12 Annual Report 2015 / Business Approach and Guidelines BUSINESS APPROACH AND GUIDELINES Strategic Context GeoPark’s objective is to create value by building the leading Latin and resources for operating and funding a business are welcoming and American upstream independent oil and gas company. By this, we increasingly more feasible. Furthermore, numerous good oil and gas assets mean an action-oriented, persistent, aware and caring company with in Latin America are available, undervalued and at very attractive prices now. the best ‘shareholder value-adding’ oil and gas assets. We believe the energy business – specifically the upstream oil and gas start with a short term ‘exit strategy’ in mind and we have focused on industry – is one of the most exciting, necessary, and economically- building a team and sustainable business. Our approach has required rewarding businesses today. No undertaking or society can advance patience in order to create the necessary foundation, but it has without the supply of energy, and energy remains the critical element enabled us to stay solidly ‘ in the game’ and be positioned to now in allowing people to better their lives. Much of the world still lacks have the chance to grab the bigger prizes. GeoPark has been conservatively built for the long term. We did not adequate energy supplies for the most basic needs and demand is continually increasing. Although new exciting technologies and The founders and our management team have a substantial part of our sources are being developed, oil and gas is the most reliable energy net worth invested in GeoPark. None of the founders have ever sold a source and will be required to support over half of our planet’s share of GeoPark stock. In fact, we have been stock buyers over time continuous and rising energy needs far into this century. (including in the NYSE IPO). The management team has no special class We believe the best places for us to find and develop hydrocarbons shareholder other than our salaries and stock performance incentive are in areas around the world where oil and gas have already been programs. The entire GeoPark team (100% of our employees have discovered, but which for economic, technical, funding or other reasons received GeoPark share awards) is solidly aligned with all of our have been inadequately developed or prematurely abandoned. These shareholders to build real and enduring value for every share of GeoPark. of stock or arrangements that benefit us differently from any other projects have proven hydrocarbon systems, valuable technical information, existing infrastructure, and, in many cases, unexploited low-risk exploration and re-development opportunities. By applying Opportunity Enhancement and Risk Diversification new technology and investment, creating stable markets and better economic conditions, and/or more efficient operations, an under- By its very nature, the upstream oil and gas business represents the performing or bypassed asset can be converted into an attractive economic undertaking of risk in search of significant rewards. To succeed, an oil project. Work in these proven areas also frequently opens up exciting new and gas company must effectively identify and manage prevailing hydrocarbon resources in new geological play types and formations. risks and uncertainties to capture the available rewards. We believe this to be one of GeoPark’s key capabilities; and our year-over-year We are focused on Latin America because of the abundance of these types track record is evidence of our success in effectively balancing risk of opportunities throughout the region. Latin America ranks as one of among the subsurface, geological, funding, organizational, market, the highest potential hydrocarbon resource regions in the world and its price, partner, shareholder, regulatory and political environments. economies are thirsty for new energy. Historically, it has been dominated For example, GeoPark was able to respond constructively to the by larger major and national oil companies, with the presence of only a 2008/9 financial crisis and, now again, to the oil volatility of 2015-2016. modest number of more-agile independent companies. North America is home to thousands of independent oil and gas operators, whereas Latin We believe the best results in the upstream business are achieved America, an area substantially larger and with greater resource potential, with a larger scale portfolio approach with multiple attractive projects has only a handful of independents taking advantage of available in multiple regions managed by talented oil and gas teams. opportunities. In contrast to many areas of the world, the environment This diversification reflects both a defensive and offensive approach. GeoPark 13 Capabilities It is protective of any downside because the collective strength Our experience in the oil and gas business has repeatedly demonstrated of our projects limits the negative impact of any underperforming the need for good people with commitment and real oil and gas asset or timing delay. It also has an exciting multiplier effect know-how. We believe in and have experienced the amazing capacity on the potential upside because of the increased number of of people to excel in an environment of expanding opportunity and opportunities independently marching ahead. These represent trust. GeoPark is blessed to have an incredible group of men and important advantages given the nature of the oil exploration women who truly work day and night to make us better in every way. and production business. Our results speak to the daily heroics (mostly unseen) by our team that keep us together and have moved us consistently closer to our goals. Our country businesses are managed by experienced local professionals and teams with respected reputations. They know both the specific Our record of delivery is based on three fundamental and distinct skill subsurface rocks and conditions and the above-ground operating and sets – as Explorers, Operators and Consolidators – which we deem business environments in each region and give us the characteristics critical for enduring success in the oil and gas business. Our team has of a local company. Our pride and care in how we act and perform in consistently demonstrated the science and creativity to find hydrocarbons our home regions are key elements of our success. in the subsurface, but also the muscle and experience to get the oil and gas out of the ground and profitably to market. Our attractive asset These generally independent businesses are further enhanced by portfolio is evidence of our ability to acquire good projects in the right being tied together by an overall corporate organization, which basins in the right countries with the right partners and at the right price. improves efficiencies, reduces costs with operational and financial synergies, controls quality, and can more effectively raise capital for Today, we have an amazing team of employees from Chile, Colombia, our projects. It also is a source for new technologies and ideas to Brazil, Peru and Argentina – each of whom joined GeoPark with the spread from one region to another. For example, our team introduced purpose of building a unique and special company that is prepared a new geological play-type to the Llanos Basin in Colombia (an area to handle challenges and seize opportunities. As a quickly growing that has been explored for more than 75 years) that resulted in company, we have repeatedly seen individuals step-up to the new multiple new oil field discoveries, and new oil technology to the responsibilities presented – and we have a deep and powerful Magallanes Basin in Chile. leadership team taking GeoPark to the next level. Importantly, through effective and controlled capital allocation, our The international upstream oil and gas business is not for the fainthearted projects within each country business can be ranked against each or easily discouraged. Time-after-time, the GeoPark team has been able other on economic, technical and strategic criteria and, therefore, to push ahead to find solutions where often others have given-up or ensure our capital resources flow to the highest performing and most failed. This is the engine and fire of our growth and the true long term attractive projects. intangible value of our Company. We are immensely grateful to all these men and women for their professionalism, discipline, unity and heart. We believe this business approach makes GeoPark a more attractive investment vehicle for all our shareholders – with a strong foundation to minimize any downside, a big upside through multiple growth New Projects and Countries opportunities, and an overall organizational system to more efficiently run and grow the individual businesses. GeoPark’s model allows We are excited about potential new business opportunities in our investors to be exposed to and benefit from the results Latin America with its high resource potential, attractive business of multiple supporting and aligned businesses across diverse environment, and limited competition. We are actively pursuing geologies and geographies. new projects in targeted proven hydrocarbon basins throughout 14 Annual Report 2015 / Business Approach and Guidelines GeoPark 15 16 Annual Report 2015 / Business Approach and Guidelines the region – selected in consideration of geological, infrastructure we believe do not properly account for multiple factors (including and regulatory factors – with our principal efforts in Colombia, Brazil, technical, cost, tax, and time) that impact the economics of oil and gas Chile, Peru, Argentina, and Mexico. projects. We also avoid markets or ‘bubbles’ when assets are over-priced. With our overall growth targets and portfolio approach, new project acquisitions are an important part of our business. Our acquisition Culture efforts begin with a technical approach to define the hydrocarbon basins where our geological and engineering teams identify an attractive ‘Creating Value and Giving Back’ is our motto and represents GeoPark’s potential. After screening for political risks, our new business teams market-based approach to align our business objectives with our core proactively ‘scratch and dig’ to locate interests or opportunities within values and responsibilities. Our in-house designed program, titled those areas and to establish a position. It is a long term and continuous S.P.E.E.D., targets and integrates the critical elements – Safety, Prosperity, effort and we have been building an attractive inventory of new Employees, Environment and Community Development – necessary projects in the region over the last ten years, aided by our team’s to make our total business plan work. Only by succeeding equally in 25+ year experience in Latin America. each of these interdependent areas can we realize our overall success and ambitions. This is important in every country where we operate, Our focus is always to build a larger scale balanced portfolio that and we make every effort to achieve the most effective governance, includes lower-risk short term cash flow generating properties, mid full compliance and consistent transparency with all relevant authorities. term medium-risk development projects, and longer term higher-risk Not only does this allow us to be a more successful business enterprise big upside projects. This permits steady secure growth with an opportunity over the long term, it reflects our pride in carrying out an important for accelerated high growth ‘home-runs’ from the bigger projects. mission in the right way. The men and women of GeoPark care passionately about how our Company acts – both internally and Good oil and gas partners are a key element of our new business externally – and we all consider our culture to be our core asset and efforts and we like to balance our acquisition risk by including the prime source of our past success and future opportunity. experienced partners in our new projects. We have developed a long term strategic alliance with LG to build a portfolio of upstream assets The world is continuously moving in a more regulated direction with across Latin America and the International Finance Corporation higher expectations, and to be able to operate in this new environment (IFC) of the World Bank is a long term principal shareholder of (and is a fundamental part of business today. We believe that GeoPark’s ability sometimes lender to and working interest partner of ) GeoPark. We to meet these challenges and perform to or beyond these ever increasing also have developed long term relationships with the national oil standards represents a competitive advantage for the future. For companies where we operate, such as with ENAP in Chile, Ecopetrol in example, the manner of, results from, and impact on the communities Colombia, Petrobras in Brazil, YPF in Argentina and Petroperu in Peru. of our overall work in Chile and Colombia provided the rationale and support for the government and regional community to allow us to Critical to the success of any new project is to conduct a thorough expand our project into new areas. It can also be meaningful and fun, technical and economic analysis prior to acquiring any new asset. such as with our full scholarships targeting young women, in the local We make sure we understand the project, its risks and its value – and communities near our field operations, for training in the sciences. we buy right. It is difficult to turn a faulty or overpriced project into a good business. Following intensive geological, geophysical, engineering, The IFC of the World Bank, our long time shareholder, has been a operational, legal and financial analyses and due diligence, we perform constructive force in helping us operate and manage our business in a detailed discounted cash flow (DCF) valuation. We also consider the consideration of the environment and communities around us. The option value or strategic benefits of a project when entering a new IFC further assists us by carrying out annual audits and physical site region. We do not buy assets on simplified ‘$ per barrel’ metrics which visits of both our regulatory compliance and best-practices approach. GeoPark 17 2015 PERFORMANCE Key Operational Results Key Financial Results Key Strategic Results Oil and Gas Production Up Cash Resources Offtake and Prepayment Agreement 23,062 boepd (4Q2015). $220 million of cash and facilities New offtake up to $100 million 20,400 boepd annual average. consisting of $83 million in cash. prepayment agreement with Trafigura to improve crude oil sales netback Oil and Gas Reserves Up Significant Cost Reduction and expand cash cushion. PDP reserves up 25% to 17.3 mmboe. CAPEX down 79%. P1 reserves up 13% to 71.1 mmboe(*). OPEX down 34%. Expansion of Argentina Portfolio 2P reserves up 3% to 125.3 mmboe(*). Cash costs per boe down 38%. Acquired 50% WI in high potential G&A down 18%. Neuquen Basin exploration block Reserve Value Drilling costs down 25%. in partnership with Wintershall. 2P reserve NPV of $1.6 billion(*). Exploration Resources at Low Oil Prices Four new hydrocarbon blocks 800 million to 1.5 billion boe(*). 85% of production is cash flow awarded in Round 13 in Reconcavo Profitable Operations Expansion of Brazilian Portfolio positive at $25-30/bbl oil prices. and Potiguar Basins. 83% Drilling Success 5 out of 6 wells drilled on production. Debt Maturity Mexico Bid Round Participation Long term debt maturity profile Participated with Grupo Alfa in Round New Gas Treatment Facilities with 80% due in 2020. 1.3, with no blocks awarded. 2009 2010 Ache gas field representing new technology in Chile. Manatí gas field compression plant in Brazil. (*) Including Peru 2008 2007 2006 18 Annual Report 2015 / Performance Oil Gas 2014 2015 2013 2012 2011 21 20 19 18 17 16 15 14 13 12 11 10 09 08 07 06 05 04 03 02 01 0 GeoPark 19 OUR STRENGTHS MExiCO KNOW-HOW ASSETS Strong Team, Capabilities, Approach and Culture. Diversified Risk-Balanced Asset Base with Proven Value, Scale and Upside. TRACK RECORD CAPiTAL Consistent Operational and Financial Growth / Ability to Unlock Value from Assets. Supporting Cash Flow, Access to Funding and Strategic Partners. GROWTH PLATFORM High-Impact Portfolio of Organic and New Project Opportunities. 20 Annual Report 2015 / Our Strengths COLOMBiA 46.5* MMBOE PERU 30.2* MMBOE BRAZiL 6.9* MMBOE CHiLE ARGENTiNA 41.8* MMBOE ASSET TyPES Production Assets Development Assets Exploration Assets Unconventional Resource Assets New Project Opportunities (*) 2P Reserves – PRMS Dec. 2015. GeoPark 21 OUR APPROACH 22 Annual Report 2015 / 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 S.P.E.E.D. program reflects this value system and represents an integrated approach to align our business objectives with our core principles and responsibilities and provides our competitive advantage. GeoPark 23 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 GeoPark is committed GeoPark is committed GeoPark is committed GeoPark is committed DEVELOPMENT to creating a safe and to delivering significant to creating a motivating to minimizing the impact GeoPark is committed healthy workplace. bottom-line financial workplace for employees. of our projects on to being the preferred Simply speaking, value to our shareholders. With today’s shortage the environment. neighbor and partner everybody must return Only a financially-healthy of capable energy As our footprint becomes by creating a mutually home everyday safe company can continue professionals, the cleaner and smaller, beneficial exchange with and sound. to grow, attract needed company which is able the more areas and the local communities resources and create real to attract, protect, retain opportunities will be where we work. Unlocking long-term benefits. and train the best team opened up for us to local knowledge creates with the best attitude work in. Our long-term and 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. 24 Annual Report 2015 / Our Value System GeoPark 25 HIGHLIGHTED SECTIONS Risk Factors Information on the Company Operating and Financial Information Directors and Management Major Shareholders and Related Parties Consolidated Financial Statements 38 65 117 141 150 172 26 Annual Report 2015 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, 2015 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 Aylwin 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. Davis Polk & Wardwell LLP 450 Lexington Avenue - New York, NY 10017 Phone: (212) 450 4000 - Fax: (212) 701 5800 Securities registered or to be registered pursuant to Section 12(b) of the Act: Title of each class Common shares, par value US$0.001 per share Name of each exchange on which registered New York Stock Exchange Securities registered or to be registered pursuant to Section 12(g) of the Act: None (Title of Class) Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None (Title of Class) Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of business covered by the annual report. Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No Common shares: 59,535,614 If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No Indicate by check mark whether the registrant has submitted electronically 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): Non-accelerated filer Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: Accelerated filer Large accelerated filer 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 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 28 GeoPark 20F 29 32 33 33 33 33 33 33 33 33 33 33 37 37 38 65 65 67 117 117 117 117 117 135 139 139 139 139 140 141 141 145 148 149 150 150 150 151 152 152 152 153 153 153 153 153 153 153 153 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 ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 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 154 154 154 157 158 158 158 161 161 161 161 161 161 161 161 161 161 162 162 162 162 162 162 162 162 162 162 162 162 163 163 163 164 164 164 165 166 166 166 166 169 173 Presentation of Financial and Other Information Certain definitions • “CNPE” are to the Brazilian National Council on Energy Policy (Conselho Unless otherwise indicated or the context otherwise requires, all references in Nacional de Política Energética ); this annual report to: • “ANH” are to the Colombian National Hydrocarbons Agency (Agencia • “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words of a Nacional de Hidrocarburos); similar effect, are to GeoPark Limited (formerly GeoPark Holdings Limited), an • “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional exempted company incorporated under the laws of Bermuda, together with de Petróleo) its consolidated subsidiaries; • “economic interest” means an indirect participation interest in the net • “Agencia” are to GeoPark Latin America Limited Agencia en Chile, an revenues from a given block based on bilateral agreements with the established branch, under the laws of Chile, of GeoPark Latin America Limited concessionaires; and (“GeoPark Latin America”), an exempted company incorporated under the • “working interest” means the right granted to the lessee of a property to laws of Bermuda; explore for and to produce and own oil, gas, or other minerals. The working • “GeoPark Colombia” are prior to our internal corporate reorganization of our interest owners bear the exploration, development and operating costs on Colombian operations, to our subsidiary GeoPark Colombia S.A., a sociedad either a cash, penalty or carried basis. 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; • “Winchester” are to our subsidiary Winchester Oil and Gas S.A., now GeoPark Colombia PN S.A. Sucursal Colombia, a Colombian branch of a sociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia SAS; • “Luna” are to our subsidiary La Luna Oil Company Limited S.A., a sociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia SAS; • “Cuerva” are to our subsidiary GeoPark Cuerva LLC, formerly known as Hupecol Caracara LLC, a limited liability company incorporated under the laws of the state of Delaware, which merged into GeoPark Colombia SAS; • “LGI” are to LG International Corp., a company incorporated under the laws of Korea; • “Gunvor” are to the Gunvor Group, a global commodity trading company; • “Methanex” are to Methanex Chile S.A., the Chilean subsidiary of the Methanex Corporation, a leading global methanol producer; • “Trafigura” are to C.I. Trafigura Petroleum Colombia S.A.S., a leading commodity trading and logistics company; • “Morona Block Acquisition” are to our pending Morona Block acquisition in Northern Peru, which is still subject to regulatory approvals. • “Notes due 2020” are to our 2013 issuance of US$300.0 million aggregate principal amount of 7.50% senior secured notes due 2020; • our “Brazil Acquisitions” are to our Rio das Contas acquisition, which we completed on March 31, 2014, our award of two new concessions by the ANP, one of which is subject to the entry into the concession agreement, in Brazil; • “US$” and “U.S. dollar” are to the official currency of the United States of America; • “Ch$” and “Chilean pesos” are to the official currency of Chile; • “Col$” and “Colombian pesos” are to the official currency of Colombia; • “AR$” and “Argentine pesos” are to the official currency of Argentina; • “real,” “reais” and “R$” are to the official currency of Brazil; • “IFRS” are to International Financial Reporting Standards as adopted by the International Accounting Standards Board, or IASB; • “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis ); GeoPark 29 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, 2015 and 2014 and for each of the years ended December 31, management and external users of our financial statements, such as industry 2015, 2014 and 2013 (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 IFRS, as issued by the International Accounting income tax, depreciation, amortization and certain non-cash items such as Standards Board (“IASB”). impairments and write-offs of unsuccessful exploration and evaluation assets, accrual of stock options and stock awards and bargain purchase gain on Our Consolidated Financial Statements have been audited by Price acquisition of subsidiaries. Adjusted EBITDA is not a measure of profit or cash Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers flows as determined by IFRS. Network (“PwC”), an independent registered public accounting firm, as stated in their report included elsewhere in this annual report. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our Our fiscal year ends December 31. References in this annual report to a fiscal operations from period to period without regard to our financing methods or year, such as “fiscal year 2015,” relate to our fiscal year ended on December 31 capital structure. We exclude the items listed above from profit for the period in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, 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 2015, 2014 and 2013. of that calendar year. 30 GeoPark 20F Oil and gas reserves and production information Rounding D&M 2015 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 in some tables may not be an arithmetic aggregation of the figures that part, from estimates of the proved reserves as of December 31, 2015. The precede them. reserves estimates are derived from the DeGolyer and MacNaughton Reserves Report (“D&M Reserves Report”), which was prepared for us by the independent reserves engineers 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, La Cuerva, Llanos 32, Llanos 34, and Yamú Blocks in Colombia, BCAM-40 (Manati) in Brazil and pro-forma estimates of 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 31 Forward-looking Statements This annual report contains statements that constitute forward-looking • market or business conditions and fluctuations in global and local demand statements. Many of the forward-looking statements contained in this annual for energy; report can be identified by the use of forward-looking words such as • the direct or indirect impact on our business resulting from terrorist incidents “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” “estimate” or responses to such incidents, including the effect on the availability of and and “potential,” among others. premiums on insurance; and • other factors discussed under “Item 3. Key Information-D. Risk factors” in this Forward-looking statements appear in a number of places in this annual annual report. report and include, but are not limited to, statements regarding our intent, belief or current expectations. Forward-looking statements are based on our Forward-looking statements speak only as of the date they are made, and we management’s beliefs and assumptions and on information currently available do not undertake any obligation to update them in light of new information to our management. Such statements are subject to risks and uncertainties, or future developments or to release publicly any revisions to these and actual results may differ materially from those expressed or implied in the statements in order to reflect later events or circumstances or to reflect the forward-looking statements due to various factors, including, but not limited occurrence of unanticipated events. 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; • our ability to complete the Morona Block Acquisition; • environmental constraints on operations and environmental liabilities arising out of past or present operations; • discovery and development of oil and natural gas reserves; • project delays or cancellations; • financial market conditions and the results of financing efforts; • political, legal, regulatory, governmental, administrative and economic conditions and developments in the countries in which we operate; • fluctuations in inflation and exchange rates in Colombia, Chile, Brazil, Argentina and in other countries in which we may operate in the future such as Peru; • 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; 32 GeoPark 20F 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 statement of income, balance sheet and cash flow data as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 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, 2013, 2012 and 2011 and for the years ended December 31, 2012 and 2011 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 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 acquisitions or Brazilian Acquisitions prior to their incorporation into our financial statements or our pending Morona Block Acquisition. GeoPark 33 Statement of income data For the year ended December 31, (in thousands of US$, except per share numbers) 2015 2014 2013 2012 2011 162,629 47,061 209,690 367,102 61,632 428,734 315,435 22,918 338,353 221,564 28,914 250,478 73,508 38,072 111,580 (86,742) (13,831) (37,471) (5,211) (105,557) (30,084) (149,574) (13,711) (232,491) (35,655) (33,474) - (131,419) (111,296) (13,002) (45,867) (24,428) (100,528) (30,367) (9,430) (1,849) 71,844 (27,622) (23,097) - (5,292) (44,962) (17,252) (69,968) (10,962) - 5,343 83,964 (33,115) (761) - (301,620) 21,125 50,088 17,054 (284,566) (50,535) (234,031) (4.05) (4.05) (5,195) 15,930 7,845 8,085 0.14 0.14 (15,154) 34,934 12,413 22,521 0.52 0.48 (76,928) (2,338) (27,788) (24,631) (53,317) (25,552) - 823 40,747 (14,227) (2,081) 8,401 32,840 (14,394) 18,446 6,567 11,879 0.28 0.27 (28,669) (2,803) (17,668) (2,546) (26,408) (5,919) (1,344) (439) 25,784 (13,052) (464) - 12,268 (7,206) 5,062 5,008 54 0.00 0.00 57,759,001 56,396,812 43,603,846 42,673,981 41,912,685 57,759,001 58,840,412 46,532,049 44,109,305 43,917,167 59,535,614 57,790,533 43,861,614 43,495,585 42,474,274 Revenue Net oil sales Net gas sales Net revenue Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful efforts Impairment loss for non-financial assets Other operating income/(expense) Operating (loss)/profit Financial costs Foreign exchange loss Bargain purchase gain on acquisition of subsidiaries (Loss) Profit before tax Income tax benefit (expense) (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 18 to our Consolidated Financial Statements. 34 GeoPark 20F Balance sheet data As of December 31, (In thousands of US$) Assets Non-current assets Property, plant and equipment Prepaid taxes Other financial assets Deferred income tax Prepayments and other receivables Total non-current assets Current assets Other financial assets Inventories Trade receivables Prepayments and other receivables Prepaid taxes 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 Current income tax Trade and other payables Total current liabilities Total liabilities 2015 2014 2013 2012 2011 522,611 1,172 13,306 34,646 220 790,767 1,253 12,979 33,195 349 595,446 457,837 224,635 11,454 5,168 13,358 6,361 10,707 7,791 13,591 510 2,957 5,226 450 707 571,955 838,543 631,787 490,436 233,975 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 - 8,532 36,917 13,993 13,459 127,672 200,573 1,039,116 58 210,886 164,613 375,557 103,569 79,126 - 8,122 42,628 35,764 6,979 121,135 214,628 846,415 44 120,426 150,371 270,841 5,116 - 3,955 32,271 49,620 3,443 48,292 137,581 628,017 43 116,817 122,561 239,421 72,665 3,000 584 15,929 24,984 147 193,650 238,294 472,269 43 112,231 96,615 208,889 41,763 365,957 312,086 250,652 343,248 42,450 19,556 16,955 342,440 46,910 16,583 30,065 290,457 33,076 8,344 23,087 422,209 435,998 354,964 35,425 208 45,790 81,423 503,632 27,153 7,935 88,904 123,992 559,990 26,630 7,231 91,633 125,494 480,458 165,046 25,991 - 17,502 208,539 27,986 7,315 72,091 107,392 315,931 134,643 9,412 - 13,109 157,164 30,613 187 33,653 64,453 221,617 Total equity and liabilities 703,799 1,039,116 846,415 628,017 472,269 GeoPark 35 Cash flow data For the year ended December 31, (In thousands of US$) Cash provided by (used in) Operating activities Investing activities Financing activities Net increase (decrease) in cash Other financial data 2015 2014 2013 2012 2011 25,895 (48,842) (18,022) (40,969) 230,746 (344,041) 124,716 11,421 127,295 (208,500) 164,018 82,813 129,427 (301,132) 26,375 (145,330) 68,763 (101,276) 131,739 99,226 For the year ended December 31, 2015 2014 2013 2012 2011 Adjusted EBITDA(1) (US$ thousands) Adjusted EBITDA margin(2) Adjusted EBITDA per boe(3) 73,787 35.2% 10.5 220,077 51.3% 33.0 167,253 49.4% 33.9 121,404 48.5% 31.1 63,391 56.8% 22.9 (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. 36 GeoPark 20F Exchange rates In Colombia, Chile, Argentina and Peru, our functional currency is the U.S. The following table presents the monthly high and low representative market dollar. In Brazil, our functional currency is the real . rate during the months indicated. The Brazilian foreign exchange system allows the purchase and sale of foreign Recent exchange rates of Real per US$ Low High currency and the international transfer of real by any person or legal entity, Month: regardless of the amount, subject to certain regulatory procedures. October 2015 November 2015 Since 1999, the Brazilian Central Bank has allowed the US$-real exchange rate December 2015 to float freely, and, since then, the US$-real exchange rate has fluctuated considerably. Our operations in Brazil account for 15% and 16% of our January 2016 February 2016 consolidated assets and 8% and 15% of our revenues for the year ended March 2016 December 31, 2014 and 2015, respectively. This portion of our business is April 2016 (through April 11, 2016) exposed to losses that may arise from currency fluctuation, as a significant amount of our revenues, operating costs, administrative expenses and taxes in Source: Central Bank of Brazil. Brazil are denominated in reais . Furthermore, we financed our acquisition of 3.7386 3.7010 3.7476 3.9863 3.8653 3.5589 3.5284 4.001 3.8745 3.9831 4.1558 4.0492 3.9913 3.6921 Rio das Contas Produtora de Petróleo Ltda. (a Brazilian limited liability The following table presents the average R$ per U.S. dollar representative company; “Rio das Contas”) in part through our Brazilian subsidiary’s entrance market rate for each of the five most recent years, calculated by using the into a US$70.5 million credit facility with Itaú BBA International plc. This average of the exchange rates on the last day of each month during the exposes us to exchange rate losses from the devaluation of the Brazilian reais period, and the representative year-end market rate for each of the five most against the U.S. dollar. recent years. In the past, the Brazilian Central Bank has occasionally intervened to control Real per US$ Low High unstable movements in foreign exchange rates. We cannot predict whether Period: the Brazilian Central Bank or the Brazilian government will continue to permit the real to float freely or will intervene in the exchange rate market through the return of a currency band system or otherwise. The real may depreciate or appreciate substantially against the U.S. dollar. Furthermore, Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of 2010 2011 2012 2013 2014 payments or there are serious reasons to foresee a serious imbalance, First quarter 2015 temporary restrictions may be imposed on remittances of foreign capital Second quarter 2015 abroad. We cannot assure you that such measures will not be taken by the Third quarter 2015 Brazilian government in the future. As a result of the devaluation that occurred Fourth quarter 2015 in the years ended December 31, 2014 and December 31, 2015, we recorded First quarter 2016 exchange rate losses amounting to US$19.2 million in 2014 and US$35.6 Second quarter 2016 (through April 11, 2016) million in 2015 in our Brazilian subsidiary. This loss was mainly generated by the credit facility of US$70.5 million that we incurred to acquire Rio das Contas Source: Central Bank of Brazil. in March 31, 2014 and certain intercompany loans. See “-D. Risk factors-Risks 1.7593 1.6746 1.9550 2.1605 2.1968 2.5750 2.8490 3.1170 3.2120 3.5589 3.5484 1.6662 1.8758 2.0435 2.3426 2.7397 3.2680 3.1790 4.194 3.9831 4.1558 3.6921 relating to our business-Our results of operations could be materially Exchange rate fluctuation may affect the US$ value of any distributions we adversely affected by fluctuations in foreign currency exchange rates.” 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 The following tables show the selling rate for the U.S. dollar for the periods and by fluctuations in foreign currency exchange rates.” dates indicated. The information in the “Average” column represents the average of the daily exchange rates during the periods presented. The B. Capitalization and indebtedness numbers in the “Period-end” column are the quotes for the exchange rate as of Not applicable. the last business day of the period in question. As of April 11, 2016, the exchange rate for the purchase of the U.S. dollar as reported by the Central C. Reasons for the offer and use of proceeds Bank of Brazil was R$3.5284 per U.S. dollar. Not applicable. GeoPark 37 Risk factors D. Risk factors • taxes and royalties under relevant laws and the terms of our contracts; Our business, financial condition and results of operations could be materially • our ability to enter into oil and natural gas sales contracts at fixed prices; and adversely affected if any of the risks described below occur. As a result, the • the level of global methanol demand and inventories and changes in the market price of our common shares could decline, and you could lose all or uses of methanol; part of your investment. This annual report also contains forward-looking • the price and availability of alternative fuels; and statements that involve risks and uncertainties. See “Forward-Looking • future changes to our hedging policies. Statements.” The risks below are not the only ones facing our Company. Additional risks not currently known to us or that we currently deem These factors and the volatility of the energy markets make it extremely difficult immaterial may also adversely affect us. Risks relating to our business to predict future oil, natural gas and methanol price movements. For example, recently, oil and natural gas prices have fluctuated significantly. From January 1, 2010 to December 31, 2015, Brent spot prices ranged from a low of US$35.26 per barrel to a high of US$128.14 per barrel, NYMEX West Texas International (“WTI”) A substantial or extended decline in oil, natural gas and methanol prices crude oil contracts prices ranged from a low of US$34.55 per bbl to a high of may materially adversely affect our business, financial condition or results US$113.39 per bbl, Henry Hub natural gas average spot prices ranged from a low of operations. of US$1.63 per mmbtu to a high of US$8.63 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$330.47 per metric ton to a high of The prices that we receive for our oil and natural gas production heavily US$634.23 per metric ton. Furthermore, oil, natural gas and methanol prices do influence our revenues, profitability, access to capital and growth rate. not necessarily fluctuate in direct relationship to each other. Historically, the markets for oil, natural gas and methanol (which have influenced prices for almost all of our Chilean gas sales) have been volatile and For the year ended December 31, 2015, 77% of our revenues, were derived from will likely continue to be volatile in the future. International oil, natural gas and oil. Because we expect that our production mix will continue to be weighted methanol prices have fluctuated widely in recent years and may continue to towards oil, our financial results are more sensitive to movements in oil prices. do so in the future. The prices that we will receive for our production and the levels of our decline in natural gas prices could negatively affect our future growth, production depend on numerous factors beyond our control. These factors particularly for future gas sales where we may not be able to secure or extend As of December 31, 2015, natural gas comprised 23% of our revenues. A include, but are not limited, to the following: • global economic conditions; our current long-term contracts. • changes in global supply and demand for oil, natural gas and methanol; Lower oil and natural gas prices may impact our revenues on a per unit basis, • the actions of the Organization of the Petroleum Exporting Countries and may also reduce the amount of oil and natural gas that can be produced (“OPEC”); economically. In addition, changes in oil and natural gas prices can impact the • political and economic conditions, including embargoes, in oil-producing valuation of our reserves and, in periods of lower commodity prices, we may countries or affecting other countries; curtail production and capital spending or may defer or delay drilling wells • the level of oil- and natural gas-producing activities, particularly in the Middle because of lower cash generation. Lower oil and natural gas prices could also East, Africa, Russia, South America and the United States; affect our growth, including future and pending acquisitions. A substantial or • the level of global oil and natural gas exploration and production activity; extended decline in oil or natural gas prices could adversely affect our • the level of global oil and natural gas inventories; business, financial condition and results of operations. • the price of methanol; • availability of markets for natural gas; For example, during 2015, we evaluated the recoverability of our fixed assets • weather conditions and other natural disasters; affected by the oil price decline and recorded impairment of non-financial • technological advances affecting energy production or consumption; assets amounting to US$149.6 million in our Chilean and Colombian assets. • domestic and foreign governmental laws and regulations, including See Note 36 to our Consolidated Financial Statements for details regarding oil environmental, health and safety laws and regulations; price scenarios, discount rates considered and sensitivity analysis affecting the • proximity and capacity of oil and natural gas pipelines and other impairment charges. transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas We have historically not hedged our production to protect against fluctuations in captive market areas; in the international oil prices. In the future, we may consider adopting a • quality discounts for oil production based, among other things, on API hedging policy against commodity price risk when deemed appropriate and and mercury content; by taking into account the size of our business and market volatility. 38 GeoPark 20F The current oil price crisis has impacted our operations and corporate strategy. estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and We face limitations on our ability to increase prices or improve margins on the the covenants in our financing agreements, as well as the amount of cash we oil and natural gas that we sell. As a consequence of the oil price crisis which can borrow using our oil reserves as collateral, the amount of cash we are able started in the second half of 2014 (WTI and Brent, the main international oil to generate from current operations and the amount of cash we can obtain price markers, fell by more than 60% between August 2014 and March 2016), from prepayment agreements. If we are not able to generate the sales which, the Company has undertaken a decisive cost cutting program to ensure its together with our current cash resources, are sufficient to fund our capital ability to both maximize ongoing projects and to preserve its cash. program, we will not be able to efficiently execute our work program, which would cause us to further decrease our work program and would harm our The main actions that were carried out to date to address the oil industry price business outlook, investor confidence and our share price. crisis include the: • reduction of our capital investment taking advantage of the flexible work In addition, actions taken by the company to maximize ongoing projects and program; to reduce expenses, including renegotiations and reduction of oil and gas • deferment of capital projects with relevant permissions and consents from service contracts and other initiatives included in the cost cutting program regulatory authorities and partners, as permitted by our contracts. adopted by us may expose us to claims and contingencies from interested • renegotiation of licenses and concessions, where permitted, and parties that may have a negative impact on our business, financial condition, renegotiation and reduction of oil and gas service contracts, including drilling results of operations and cash flows. If oil prices continue to remain low we and civil work contractors, as well as transportation, trucking and pipeline may be unable to meet our contractual obligations with oil and service costs; and contracts and our suppliers. Equally, those third parties may be unable to meet • improving the efficiency of our operating costs and the temporary their contractual obligations to us as a result of the oil price crisis, impacting suspension of certain low-margin producing oil and gas fields. on our operations. During 2015, we took decisive steps to adapt to the new oil price environment. In budgeting for our future activities, we have relied on a number of We reduced our 2015 capital expenditure program by 79% year-over-year and assumptions, including, with regard to our discovery success rate, the number implemented significant cost reduction initiatives that resulted in production of wells we plan to drill, our working interests in our prospects, the costs and operating costs being reduced by 34%, drilling costs being reduced by involved in developing or participating in the development of a prospect, the approximately 25%, and administrative and selling expenses being reduced by timing of third-party projects and our ability to obtain needed financing in 39%, while achieving an average production of 20,367 boepd and increasing respect to any further acquisitions and the availability of both suitable our proved reserves to 48.6 mmboe. equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and Oil prices were volatile since the end of 2014 and have remained at low levels competitive uncertainties, conditions in the financial markets, contingencies in the first part of 2016. In preparation for continued volatility, we developed and risks, all of which are difficult to predict and many of which are beyond our multiple scenarios for our 2016 capital expenditure program, as follows: control. In addition, we opportunistically seek out new assets and acquisition targets to complement our existing operations, and have financed such Our preliminary base capital program for 2016 considers a reference oil price acquisitions in the past through the incurrence of additional indebtedness, assumption of US$35-US$40 per barrel and calls for approximately US$45 including additional bank credit facilities, equity issuances or the sale of million-US$55 million to fund our exploration and development, which we intend minority stakes in certain operations to our partners. We may need to raise to fund through cash flows from operations and cash-in-hand. In addition, we additional funds more quickly if one or more of our assumptions prove to be have developed downside and upside work program scenarios based on different incorrect or if we choose to expand our hydrocarbon asset acquisition, oil prices and project performance. The downside scenario work program exploration, appraisal or development efforts more rapidly than we presently considers a reference oil price assumption of US$25-US$30 per barrel and consists anticipate, and we may decide to raise additional funds even before we need of an alternative capital expenditure program of approximately US$20 million- them if the conditions for raising capital are favorable. The ultimate amount of US$25 million consisting mainly of certain low risk and quick cash flow generating capital that we will expend may fluctuate materially based on market projects. The upside scenario work program considers a reference oil price conditions, our continued production, decisions by the operators in blocks assumption of US$50 per barrel or higher and consists of an alternative capital where we are not the operator, the success of our drilling results and future expenditure program of approximately US$75 million-US$90 million to be acquisitions. Our future financial condition and liquidity will be impacted by, selected from identified projects designed to increase reserves and production. among other factors, our level of production of oil and natural gas and the Funding for these programs relies in part on oil prices remaining close our appraisal drilling program, the number of commercially viable oil and natural prices we receive from the sale thereof, the success of our exploration and GeoPark 39 gas discoveries made and the quantities of oil and natural gas discovered, the We derive a significant portion of our revenues from sales to a few key speed with which we can bring such discoveries to production and the actual customers. cost of exploration, appraisal and development of our oil and natural gas assets. In Chile, 100% of our crude oil and condensate sales are made to ENAP. For Unfavorable credit and market conditions, such as the global financial crisis the year ended December 31, 2015, sales to ENAP represented 15% of our that began in 2008 or the recent decline in oil prices have affected and could total revenues. ENAP imports the majority of the oil it refines and partially continue to affect negatively the economies of the countries in which we supplements those imports with volumes supplied locally by its own operate and may negatively affect our business, and results of operations. operated fields and those operated by us. The sales contract with ENAP is commonly revised every year to reflect changes in the global oil market and Global financial crises and related turmoil in the global financial system have to adjust for ENAP’s logistics costs in the Gregorio oil terminal. As of the date had, and may continue to have, a negative impact on our business, financial of this annual report, we are negotiating a new agreement with ENAP that condition, results of operations and cash flows. In addition, the recent decline will take effect in June 2016. In addition, in Chile, in the year ended in WTI and Brent, the main international oil price markers, that fell by more December 31, 2015, almost all of our natural gas sales were made to than 60% between August 2014 and March 2016 and which are expected to Methanex under a long-term contract, the “Methanex Gas Supply remain volatile in the near future, may also negatively affect the economies of Agreement”, which expires on April 30, 2017. Sales to Methanex represented the countries in which we operate. Any of the foregoing factors or a 7% of our consolidated revenues for the year ended December 31, 2015. combination of these factors could have an adverse effect on our results of However, if ENAP or Methanex were to decrease or cease purchasing our oil operations and financial condition. and gas, or if we were unable to renew these contracts at a lower sales price or at all, this could have a material adverse effect on our business, financial Unless we replace our oil and natural gas reserves, our reserves and condition and results of operations production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and In Colombia, for the year ended December 31, 2015, we made 62.1% of our oil the identified locations in which we drill in the future may not yield oil or sales to Gunvor, 12.6% to Trafigura and 9.2% to Petrominerales, with sales to natural gas in commercial quantities. Gunvor accounting for 39.1%, Trafigura for 7.9% and Petrominerales for 5.8% of our consolidated revenues for the same period. Sales for the year ended Production from oil and gas properties declines as reserves are depleted, with the December 31, 2015 were made under short-term agreements. In 2016 we are rate of decline depending on reservoir characteristics. Accordingly, our current expected to sell most of our production to Trafigura and BP under new proved reserves will decline as these reserves are produced. As of December 31, long-term agreements. If any of our buyers were to decrease or cease 2015, our reserves-to-production (or reserve life) ratio for net proved reserves in purchasing oil from us, or if any of them were to decide not to renew their Colombia, Chile and Brazil was 6.6 years. According to estimates, if on January 1, contracts with us or to renew them at a lower sales price, this could have a 2016, we ceased all drilling and development activities, including recompletions, material adverse effect on our business, financial condition and results of refracs and workovers, our proved developed producing reserves base in operations. See “Item 4. Information on the Company-B. Business overview- Colombia, Chile and Brazil would decline at an average annual effective rate of Significant agreements-Colombia” 33% over the first three years, including 8% during the first year. Our future oil and natural gas reserves and production, and therefore our cash Field in Brazil were generated from sales to Petróleo Brasileiro S.A. (“Petrobras”), flows and income, are highly dependent on our success in efficiently the operator of the Manati Field, pursuant to a long-term gas off-take contract. developing our current reserves and using cost-effective methods to find or See “Item 4. Information on the Company-B. Business overview-Significant acquire additional recoverable reserves. While we have had success in agreements-Brazil-Petrobras Natural Gas Purchase Agreement.” In Brazil, all of our revenues from the sale of gas and condensate in the Manati identifying and developing commercially exploitable fields and drilling locations in the past, we may be unable to replicate that success in the future. In Peru, subject to the pending government approval of the assignment to us We may not identify any more commercially exploitable fields or successfully of 75% in the Morona Block (also known as Lote 64), and other environmental drill, complete or produce more oil or gas reserves, and the wells which we have permits and if we are able to start producing oil from this block, Petróleos de drilled and currently plan to drill within our blocks or concession areas may not Perú S.A. (a sociedad anónima incorporated under the laws of Peru; discover or produce any further oil or gas or may not discover or produce hereinafter “Petroperu”) has the first option but not the obligation to purchase additional commercially viable quantities of oil or gas to enable us to continue oil produced by us in the Morona Block. to operate profitably. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial Our results of operations could be materially adversely affected by condition and results of operations will be materially adversely affected. fluctuations in foreign currency exchange rates. 40 GeoPark 20F Although a majority of our net revenues is denominated in US$, unfavorable factors include, but are not limited to, proximity and capacity of pipelines and fluctuations in foreign currency exchange rates for certain of our expenses in other means of transportation, the availability of upgrading and processing Colombia, Chile, Brazil, Peru and Argentina could have a material adverse effect facilities, equipment availability and government laws and regulations on our results of operations. A portion of the cost reductions that we achieved (including, without limitation, laws and regulations relating to prices, sale in 2015 were related to the depreciation of local currencies, including mainly restrictions, taxes, governmental stake, allowable production, importing and the Co$, the Ch$ and the Brazilian real . An appreciation of local currencies can exporting of oil and natural gas, environmental protection and health and increase our costs and negatively impact our results from operations. safety). The effect of these factors, individually or jointly, cannot be accurately predicted, but may have a material adverse effect on our business, financial Furthermore, we have not entered, into derivative transactions to hedge the condition and results of operations. 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 There can be no assurance that our drilling programs will produce oil and revenues, expenses and income, as well as assets and liabilities, into US$ at natural gas in the quantities or at the costs anticipated, or that our currently exchange rates in effect during or at the end of each reporting period. producing projects will not cease production, in part or entirely. Drilling programs may become uneconomic as a result of an increase in our Through our Brazilian operations, we are exposed to fluctuations in the real operating costs or as a result of a decrease in market prices for oil and natural against the US$, as our Brazilian revenues and expenses are mostly gas. Our actual operating costs or the actual prices we may receive for our oil denominated in reais . The real has experienced frequent and substantial and natural gas production may differ materially from current estimates. In variations in relation to the US$ and other foreign currencies. For example, the addition, even if we are able to continue to produce oil and gas, there can be real was R$1.56 per US$1.00 in August 2008. Following the onset of the crisis no assurance that we will have the ability to market our oil and gas in the global financial markets, the real depreciated 31.9% against the US$ production. See “-Our inability to access needed equipment and and reached R$2.34 per US$1.00 at the end of 2008. In 2014 and 2015, infrastructure in a timely manner may hinder our access to oil and natural gas however, the real depreciated, and on December 31, 2015, the exchange rate markets and generate significant incremental costs or delays in our oil and was R$3.9085 per US$1.00. In the first three months of 2016, the real natural gas production” below. appreciated and the exchange rate as of March 31, 2016 was R$3.5589 per US$1.00. Depending on the circumstances, either depreciation or appreciation Our identified potential drilling location inventories are scheduled over of the real could materially and adversely affect the growth of the Brazilian many years, making them susceptible to uncertainties that could materially economy and our business, financial condition and results of operations. For alter the occurrence or timing of their drilling. example, in 2014 and 2015, we recorded exchange rate losses amounting to US$19.2 million and US$35.6 million in our Brazilian subsidiary that were Our management team has specifically identified and scheduled certain mainly generated by the credit facility of US$70.5 million that we incurred to potential drilling locations as an estimation of our future multi-year drilling acquire Rio das Contas in March 31, 2014 and certain intercompany loans. See activities on our existing acreage. As of December 31, 2015, approximately 95 “-A. Selected financial data-Exchange rates.” of our specifically identified potential future drilling locations were attributed to proved undeveloped reserves in Colombia, Chile and Brazil. These identified There are inherent risks and uncertainties relating to the exploration and potential drilling locations, including those without proved undeveloped production of oil and natural gas. reserves, represent a significant part of our growth strategy. Our performance depends on the success of our exploration and production Our ability to drill and develop these identified potential drilling locations activities and on the existence of the infrastructure that will allow us to take depends on a number of factors, including oil and natural gas prices, the advantage of our oil and gas reserves. Oil and natural gas exploration and availability and cost of capital, drilling and production costs, the availability of production activities are subject to numerous risks beyond our control, drilling services and equipment, drilling results, lease expirations, the including the risk that exploration activities will not identify commercially availability of gathering systems, marketing and transportation constraints, viable quantities of oil or natural gas. Our decisions to purchase, explore, refining capacity, regulatory approvals and other factors. Because of the develop or otherwise exploit prospects or properties will depend in part on the uncertainty inherent in these factors, there can be no assurance that the evaluation of seismic and other data obtained through geophysical, numerous potential drilling locations we have identified will ever be drilled or, geochemical and geological analysis, production data and engineering studies, if they are, that we will be able to produce oil or natural gas from these or any the results of which are often inconclusive or subject to varying interpretations. other potential drilling locations. Furthermore, the marketability of any oil and natural gas production from our projects may be affected by numerous factors beyond our control. These GeoPark 41 Our business requires significant capital investment and maintenance • licenses, permits and other authorizations for drilling operations; expenses, which we may be unable to finance on satisfactory terms or at all. • reports concerning operations; • compliance with environmental, health and safety laws and regulations; Because the oil and natural gas industry is capital intensive, we expect to make • drafting and implementing emergency planning; substantial capital expenditures in our business and operations for the • plugging and abandonment costs; and exploration and production of oil and natural gas reserves. We made US$45.4 • taxation. million and US$353.0 million (including the acquisition in Brazil of Rio das Contas) of capital expenditures during the years ended December 31, 2015 Under these laws and regulations, we could be liable for, among other things, and 2014, respectively. See “Item 5. Operating and Financial Review and personal injury, property damage, environmental damage and other types of Prospects-B. Liquidity and capital resources-Capital expenditures” for expected damage. Failure to comply with these laws and regulations may also result in the capital expenditures in 2016. suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in The actual amount and timing of our future capital expenditures may differ ways that could substantially increase our costs. Any such liabilities, obligations, materially from our estimates as a result of, among other things, commodity penalties, suspensions, terminations or regulatory changes could have a material prices, actual drilling results, the availability of drilling rigs and other adverse effect on our business, financial condition or results of operations. equipment and services, and regulatory, technological and competitive developments. In response to changes in commodity prices, we may increase In addition, the terms and conditions of the agreements under which our oil and or decrease our actual capital expenditures. We intend to finance our future gas interests are held generally reflect negotiations with governmental authorities capital expenditures through cash generated by our operations and potential and can vary significantly. These agreements take the form of special contracts, future financing arrangements. However, our financing needs may require us concessions, licenses, associations or other types of agreements. Any suspensions, to alter or increase our capitalization substantially through the issuance of terminations or regulatory changes in respect of these special contracts, debt or equity securities or the sale of assets. concessions, licenses, associations or other types of agreements could have a material adverse effect on our business, financial condition or results of operations. If our capital requirements vary materially from our current plans, we may require further financing. In addition, we may incur significant financial Oil and gas operations contain a high degree of risk and we may not be fully indebtedness in the future, which may involve restrictions on other financing insured against all risks we face in our business. and operating activities. We may also be unable to obtain financing or financing on terms favorable to us. These changes could cause our cost of Oil and gas exploration and production is speculative and involves a high doing business to increase, limit our ability to pursue acquisition opportunities, degree of risk and hazards. In particular, our operations may be disrupted by reduce cash flow used for drilling and place us at a competitive disadvantage. risks and hazards that are beyond our control and that are common among oil A significant reduction in cash flows from operations or the availability of and gas companies, including environmental hazards, blowouts, industrial credit could materially adversely affect our ability to achieve our planned accidents, occupational safety and health hazards, technical failures, labor growth and operating results. disputes, community protests or blockades, unusual or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather We are subject to complex laws common to the oil and natural gas industry, conditions, explosions and other accidents. For example, in the first half of which can have a material adverse effect on our business, financial 2013 we experienced a well control incident at our Chercán 1 well in the condition and results of operations. Flamenco Block in Chile with no harm to employees or property. While we were able to bring that incident under control without injuries or The oil and natural gas industry is subject to extensive regulation and environmental damage, there can be no assurance that we will not experience intervention by governments throughout the world, including extensive local, similar or more serious incidents in the future, which could result in damage to, state and federal regulations, in such matters as the award of exploration and or destruction of, wells or production facilities, personal injury, environmental production interests, the imposition of specific exploration and drilling damage, business interruption, financial losses and legal liability. obligations, allocation of and restrictions on production, price controls, required divestments of assets and foreign currency controls, and the development and While we believe that we maintain customary insurance coverage for nationalization, expropriation or cancellation of contract rights. companies engaged in similar operations, we are not fully insured against all We have been required in the past, and may be required in the future, to make contain significant exclusions from and limitations on coverage. We may elect significant expenditures to comply with governmental laws and regulations, not to obtain certain non-mandatory types of insurance if we believe that the including with respect to the following matters: cost of available insurance is excessive relative to the risks presented. The risks in our business. In addition, insurance that we do and may carry may 42 GeoPark 20F occurrence of a significant event or a series of events against which we are not the use of new and advanced technologies, which can be expensive to develop, fully insured and any losses or liabilities arising from uninsured or purchase and implement and may not function as expected. Such uncertainties underinsured events could have a material adverse effect on our business, and operating risks associated with development projects could have a material financial condition or results of operations. adverse effect on our business, 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 to Development of projects may be materially adversely affected by one or more 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 gas • delays in delivery of equipment and materials; properties and exploratory prospects and to evaluate, bid for and purchase a • our ability to close our pending Morona Block Acquisition. greater number of properties and prospects than our financial or personnel • labor disputes; • political events; • title problems; 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 • obtaining easements and rights of way; for investment in the oil and natural gas industry. As a result of each of the • blockades or embargoes; • litigation; aforementioned, we may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, • compliance with governmental laws and regulations, including attracting and retaining quality personnel or raising additional capital, which environmental, health and safety laws and regulations; could have a material adverse effect on our business, financial condition or • adverse weather conditions; • unanticipated increases in costs; • natural disasters; • accidents; • transportation; • unforeseen engineering and drilling complications; • environmental or geological uncertainties; and • other unforeseen circumstances. results of operations. See “Item 4. Information on the Company-B. Business overview-Our competition.” Our estimated oil and gas reserves are based on assumptions that may prove inaccurate. Our oil and gas reserves estimates in Colombia, Chile, Brazil, and Peru as of December 31, 2015 are based on the D&M Reserves Report. Although classified as “proved reserves,” the reserves estimates set forth in the D&M Any of these events or other unanticipated events could give rise to delays in Reserves Reports are based on certain assumptions that may prove development and completion of our projects and cost overruns. inaccurate. D&M’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future For example, in 2013, the drilling and completion cost for the exploratory well expenditures and other economic assumptions (including interests, royalties Chilco x-1 in our Flamenco Block in Chile was originally estimated at US$2.6 and taxes) as provided by us. million, but the actual cost was approximately US$4.0 million, mainly due to mechanical issues during the drilling as it was the first well drilled with a new In Chile, D&M’s estimates are based in part on the assumption that Methanex drilling rig. continues to commit to purchase Fell Block gas under the existing long-term Delays in the construction and commissioning of projects or other technical contract beyond 2017. difficulties may result in future projected target dates for production being delayed In Peru, the estimates are formulated on a pro forma basis because the Morona or further capital expenditures being required. These projects may often require Block Acquisition is subject to approval by the Peruvian government. GeoPark 43 Oil and gas reserves engineering is a subjective process of estimating accumulations pipelines were unavailable, this could have a materially adverse effect on our of oil and gas that cannot be measured in an exact way, and estimates of other ability to deliver and sell our product to Methanex, which could have a engineers may differ materially from those set out herein. Numerous assumptions material adverse effect on our gas sales. In addition, gas production in some and uncertainties are inherent in estimating quantities of proved oil and gas areas in the Tierra del Fuego Blocks and the Otway and Tranquilo Blocks could reserves, including projecting future rates of production, timing and amounts of require us to build a new network of gas pipelines in order for us to be able to development expenditures and prices of oil and gas, many of which are beyond our deliver our product to market, which could require us to make significant control. Results of drilling, testing and production after the date of the estimate may capital investments. require revisions to be made. For example, if we are unable to sell our oil and gas to customers, this may impact the estimate of our oil and gas reserves. Accordingly, In Colombia, producers of crude oil have historically suffered from tanker reserves estimates are often materially different from the quantities of oil and gas transportation logistics issues and limited storage capacity, which cause delays that are ultimately recovered, and if such recovered quantities are substantially in delivery and transfer of title of crude oil. Such capacity issues in Colombia lower that the initial reserves estimates, this could have a material adverse impact may require us to transport crude from our Colombian operations via truck, on our business, financial condition and results of operations. which may increase the costs of those operations. Road infrastructure is limited in certain areas in which we operate, and certain communities have Our inability to access needed equipment and infrastructure in a timely used and may continue to use road blockages, which can sometimes interfere manner may hinder our access to oil and natural gas markets and generate with our operations in these areas. For example, in December 2014, our significant incremental costs or delays in our oil and natural gas production. Colombian production had been impacted by approximately 5,000 bopd during the last 13 days of the year by a road blockage, which was restored to Our ability to market our oil and natural gas production depends substantially normal production levels by the beginning of January 2015. on the availability and capacity of processing facilities, oil tankers, transportation facilities (such as pipelines, crude oil unloading stations and While Brazil has a well-developed network of hydrocarbon pipelines, storage trucks) and other necessary infrastructure, which may be owned and operated and loading facilities, we may not be able to access these facilities when by third parties. Our failure to obtain such facilities on acceptable terms or on needed. Pipeline facilities in Brazil are often full and seasonal capacity a timely basis could materially harm our business. We may be required to shut restrictions may occur, particularly in natural gas pipelines. Our failure to down oil and gas wells because access to transportation or processing secure transportation or access to pipelines or other facilities once we facilities may be limited or unavailable when needed. If that were to occur, commence operations in the concessions we were awarded in Brazil on then we would be unable to realize revenue from those wells until acceptable terms or on a timely basis could materially harm our business. arrangements were made to deliver the production to market, which could cause a material adverse effect on our business, financial condition and results In Peru, future production in the Morona Block is expected to be transported of operations. In addition, the shutting down of wells can lead to mechanical through the existing North Peruvian Pipeline, which currently has enough idle problems upon bringing the production back on line, potentially resulting in capacity to transport such future production. However, infrastructure decreased production and increased remediation costs. The exploitation and problems or social unrest affecting the pipeline operation may adversely affect sale of oil and natural gas and liquids will also be subject to timely commercial our production or revenues related to the Morona Block. In addition, as the processing and marketing of these products, which depends on the Morona Block is located in a remote area of the tropical rainforest, the contracting, financing, building and operating of infrastructure by third parties. development of the project involves that significant infrastructure has to be In Chile, we transport the crude oil we produce in the Fell Block by truck to pipeline from the site to the North Peruvian Pipeline. Also, as there are no ENAP’s processing, storage and selling facilities at the Gregorio Refinery. As of roads available in the surrounding area, logistics will be performed by the date of this annual report, ENAP purchases all of the crude oil we produce helicopters or barges during specific seasons of the year. built, as processing facilities, storages tanks and an approximately 97 km in Chile. We rely upon the continued good condition, maintenance and accessibility of the roads we use to deliver the crude oil we produce. If the Our use of seismic data is subject to interpretation and may not accurately condition of these roads were to deteriorate or if they were to become identify the presence of oil and natural gas. inaccessible for any period of time, this could delay delivery of crude oil in Chile and materially harm our business. For example, in January 2011, social Even when properly used and interpreted, seismic data and visualization and labor unrest resulted in the roads to the Gregorio Refinery being closed techniques are tools only used to assist geoscientists in identifying subsurface for two days, and we were unable to deliver crude oil to ENAP. structures as well as eventual hydrocarbon indicators, and do not enable the In the Fell Block, we depend on ENAP-owned gas pipelines to deliver the gas structures. In addition, the use of seismic and other advanced technologies we produce to Methanex, the sole purchaser of the gas we produce. If ENAP’s requires greater pre-drilling expenditures than traditional drilling strategies, interpreter to know whether hydrocarbons are, in fact, present in those 44 GeoPark 20F and we could incur losses as a result of these expenditures. Because of these associated costs, or the rate of production of any non-operated and, to an uncertainties associated with our use of seismic data, some of our drilling extent, any non-wholly-owned, assets.” activities may not be successful or economically viable, and our overall drilling success rate or our drilling success rate for activities in a particular area could Our pending acquisition of the Morona Block in Peru is subject to regulatory decline, which could have a material adverse effect on us. approvals. Through our Brazilian operations, we face operational risks relating to In October 2014 we agreed to acquire from Petroperu a 75% working interest offshore drilling that we have not faced in the past. in the Morona Block in Northern Peru. We have been qualified as an operator To date, we have operated solely as an onshore oil and gas exploration and promoting, negotiating, underwriting and monitoring of exploration and production company. However, our operations in the BCAM-40 Concession in exploitation of hydrocarbons contracts in Peru; hereinafter “Perupetro”), the Brazil may include shallow-offshore drilling activity in two areas in the Peruvian hydrocarbons licensing agency. The closing of the acquisition is Camamu-Almada Basin, which we expect will continue to be operated by subject to the occurrence of certain conditions, including obtaining other by Perupetro S.A. (the Peruvian state-owned company responsible for Petrobras. governmental approvals. The current agreement provides until June 30, 2016 to obtain regulatory approvals. If the conditions precedent are not satisfied by Offshore operations are subject to a variety of operating risks and laws and such date, each party will have the right to terminate the contract without regulations, including among other things, with respect to environmental, liability. The parties have repeatedly amended the deadline to obtain health and safety matters, specific to the marine environment, such as regulatory approvals in the past to provide sufficient time to complete the capsizing, collisions and damage or loss from hurricanes or other adverse regulatory approval process. We are currently evaluating a new deadline weather conditions. These conditions can cause substantial damage to facilities extension with Petroperu, but we cannot be sure that the extension will occur and interrupt production. As a result, we could incur substantial liabilities, or that we will be able to obtain the required regulatory approvals. Presidential compliance costs, fines or penalties that could reduce or eliminate the funds elections taking place in 2016 in Peru could also affect regulatory approval of available for exploration, development or leasehold acquisitions, or result in the Morona Block Acquisition. See “Item 4. Information on the Company-B. loss of equipment and properties. For example, the Manati Field has been Business overview-Significant agreements-Peru-Morona Block Acquisition.” subject to administrative infraction notices, which have resulted in fines against Petrobras in an aggregate amount of US$12.5 million, all of which are pending We may suffer delays or incremental costs due to difficulties in negotiations a final decision of the Brazilian Institute for the Environment and Natural with landowners and local communities, including native communities, Renewable Resources ( Instituto Brasileiro do Meio-Ambiente e dos Recursos where our reserves are located. Naturais Renováveis ). Although the administrative fines were filed against Petrobras, as a party to the concession agreement governing the Manati Field, Access to the sites where we operate requires agreements (including, for Rio das Contas may be liable up to its participation interest of 10%. example, assessments, rights of way and access authorizations) with landowners and local communities. If we are unable to negotiate agreements Additionally, offshore drilling generally requires more time and more with landowners, we may have to go to court to obtain access to the sites of advanced drilling technologies, involving a higher-risk of technological failure our operations, which may delay the progress of our operations at such sites. and usually higher drilling costs. Offshore projects often lack proximity to In Chile, for example, we have negotiated the necessary agreements for many existing oilfield service infrastructure, necessitating significant capital of our current operations in the Magallanes Basin. In the Tierra del Fuego investment in flow line infrastructure before we can market the associated oil Blocks, although we have successfully negotiated access to our sites, any or gas of a commercial discovery, increasing both the financial and operational future disputes with landowners or court proceedings may delay our risk involved with these operations. Because of the lack and high cost of operations in Tierra del Fuego Blocks. In Brazil, in the event that social unrest infrastructure, some offshore reserve discoveries may never be produced that occurred in 2013 and March 2016 continues or intensifies, this may lead to economically. delays or damage relating to our ability to operate the assets we have acquired or may acquire in our Brazil Acquisitions. Further, because we are not the operator of our offshore fields, all of these risks may be heightened since they are outside of our control. We have a 10% In Colombia, although we have agreements with many landowners and are in interest in the Manati Field which limits our operating flexibility in such negotiations with others, we expect our costs to increase following current offshore fields. See “-We are not, and may not be in the future, the sole owner and future negotiations regarding access to our blocks, as the economic or operator of all of our licensed areas and do not, and may not in the future, expectations of landowners have generally increased, which may delay access hold all of the working interests in certain of our licensed areas. Therefore, we to existing or future sites. In addition, the expectations and demands of local may not be able to control the timing of exploration or development efforts, communities on oil and gas companies operating in Colombia have increased GeoPark 45 in the wake of recent changes to the royalty regime in Colombia. As a result, example, at the end of the first exploration period on November 13, 2015, local communities have demanded that oil and gas companies invest in pursuant to the Flamenco Block CEOP, we returned 25% of the acreage and kept a remediating and improving public access roads, compensate them for any reduced area for the second exploration period. See “Item 4. Information on the damages related to use of such roads and, more generally, invest in Company-B. Business overview-Our operations-Operations in Chile.” infrastructure that was previously paid for with public funds. Due to these circumstances, oil and gas companies in Colombia, including us, are now In Peru, the rights to explore and produce hydrocarbons are granted through a dealing with increasing difficulties resulting from instances of social unrest, license contract signed with Perupetro. The scope and schedule of such temporary road blockages and conflicts with landowners. For example, in development will depend on us and Petroperu. The license contract could be December 2014, production from certain fields in the Llanos 34 Block was terminated by Perupetro if the development obligations included in such affected by a road blockage resulting in our reduction of production for a agreement are not fulfilled. In addition, there is also an exploratory period of thirteen days that was returned to normal in early January 2015. commitment consisting of the drilling of one exploratory well every two and a half years. Failure to fulfill the exploratory commitment will lead to acreage There can be no assurance that disputes with landowners and local relinquishment materially affecting the project. Moreover, we have entered communities will not delay our operations or that any agreements we reach into a Joint Investment Agreement with Petroperu by which we are obliged to with such landowners and local communities in the future will not require us bear 100% of capital cost required to carry out long test to existing wells to incur additional costs, thereby materially adversely affecting our business, Situche Central 2X and Situche Central 3X. Failure to do so will result in the loss financial condition and results of operations. Local communities may also of our participating interest in the License Contract of the Morona Block, and protest or take actions that restrict or cause their elected government to subject us to possible damage claims from Petroperu. restrict our access to the sites of our operations, which may have a material adverse effect on our operations at such sites. For additional details regarding the status of our operations with respect to our various special contracts and concession agreements, see “Item 4. In Peru, the Morona Block is located in land inhabited by native communities. Information on the Company-B. Business overview-Our operations.” Land use agreements will have to be signed with the communities and social support programs are expected to be implemented by us. In the Morona Block, A significant amount of our reserves and production have been derived approximately seventy-five indigenous communities, which fall into twelve from our operations in three blocks, the Llanos 34 in Colombia, the Fell Block distinct community structures, have been identified. Despite indigenous in Chile and the BCAM-40 Concession in Brazil. community support for hydrocarbons activities since the mid-nineties, similar projects in the Peruvian rainforest have faced social conflicts and works delays For the year ended December 31, 2015, the Llanos 34 Block contained 59% of due to community claims. our net proved reserves and generated 59% of our production, the Fell Block contained 24% of our net proved reserves and generated 18% of our total Under the terms of some of our various CEOPs, E&P Contracts and concession production and the BCAM-40 Concession contained 13% of our net proved agreements, we are obligated to drill wells, declare any discoveries and file reserves and generated 16% of our production. While our recent expansion periodic reports in order to retain our rights and establish development into Brazil, Colombia and Argentina with new exploratory blocks incorporated areas. Failure to meet these obligations may result in the loss of our interests in our portfolio (and our expected future expansion into Peru) mean that the in the undeveloped parts of our blocks or concession areas. above mentioned blocks may be expected to be a less significant component of our overall business, we cannot be sure that we will be able to continue In order to protect our exploration and production rights in our license areas, we diversifying our reserves and production. Resulting from these, any must meet various drilling and declaration requirements. In general, unless we government intervention, impairment or disruption of our production due to make and declare discoveries within certain time periods specified in our various factors outside of our control or any other material adverse event in our special operation contracts ( Contratos Especiales de Operación para la operations in such blocks would have a material adverse effect on our Exploración y Explotación de Yacimientos de Hidrocarburo ; hereinafter “CEOP”), business, financial condition and results of operations. E&P Contracts and concession agreements, our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified under Our contracts in obtaining rights to explore and develop oil and natural gas these contracts and agreements yield discoveries, we may face delays in drilling reserves are subject to contractual expiration dates and operating these prospects or be required to relinquish these prospects. The costs to maintain conditions, and our CEOPs, E&P Contracts and concession agreements are or operate the CEOPs, E&P Contracts and concession agreements over such areas subject to early termination in certain circumstances. may fluctuate and may increase significantly, and we may not be able to meet our commitments under such contracts and agreements on commercially reasonable Under certain of the CEOPs, E&P Contracts and concession agreements to terms or at all, which may force us to forfeit our interests in such areas. For which we are or may in the future become parties, we are or may become 46 GeoPark 20F subject to guarantees to perform our commitments and/or to make payment Information on the Company-B. Business overview-Significant agreements- for other obligations, and we may not be able to obtain financing for all such Chile-CEOPs.” There can be no assurance that the early termination of any of obligations as they arise. If such obligations are not complied with when due, our CEOPs would not have a material adverse effect on us. in addition to any other remedies that may be available to other parties, this could result in cancelation of our CEOPs, E&P Contracts and concession In addition, according to the Chilean Constitution, Chile is entitled to agreements or dilution or forfeiture of interests held by us. As of December 31, expropriate our rights in our CEOPs for reasons of public interest. Although 2015, the aggregate outstanding amount of this potential liability for Chile would be required to indemnify us for such expropriation, there can be guarantees was approximately US$78 million, mainly relating to guarantees of no assurance that any such indemnification will be paid in a timely manner or our minimum work program for the VIM 3 Block in Colombia, our minimum in an amount sufficient to cover the harm to our business caused by such work program for Tierra del Fuego Blocks in Chile and, to a lesser extent, expropriation. minimum work programs for our other Colombian operations, the Brazilian concession areas and the new blocks in Argentina. See Note 31(b) to our In Colombia, our E&P Contracts may be subject to early termination for a Consolidated Financial Statements. breach by the parties, a default declaration, application of any of the contracts’ unilateral termination clauses or pursuant to termination clauses mandated by Additionally, certain of the CEOPs, E&P Contracts and concession agreements Colombian law. Anticipated termination declared by the ANH results in the to which we are or may in the future become a party are subject to set immediate enforcement of monetary guaranties against us and may result in expiration dates. Although we may want to extend some of these contracts an action for damages by the ANH and/or a restriction on our ability to engage beyond their original expiration dates, there is no assurance that we can do so in contracts with the Colombian government during a certain period of time. on terms that are acceptable to us or at all, although some CEOPs contain See “Item 4. Information on the Company-B. Business overview-Significant provisions enabling exploration extensions. agreements-Colombia-E&P Contracts.” In particular, in Chile, our CEOPs provide for early termination by Chile in In Brazil, concession agreements generally may be renewed, at the ANP’s certain circumstances, depending upon the phase of the CEOP. For example, discretion, for an additional period, provided that a renewal request is made at pursuant to the Fell Block CEOP, under which we are in the exploitation phase, least 12 months prior to the termination of the concession agreement and Chile may terminate the CEOP if (i) we stop performing any of the substantial there has not been a breach of the terms of the concession agreement. We obligations assumed under the Fell Block CEOP without cause and do not cure expect that all our concession agreements will provide for early termination in such nonperformance pursuant to the terms of the concession, following the event of: (i) government expropriation for reasons of public interest; (ii) notice of breach or (ii) our oil activities are interrupted for more than three revocation of the concession pursuant to the terms of the concession years due to force majeure circumstances (as defined in the Fell Block CEOP). If agreement; or (iii) failure by us or our partners to fulfill all of our respective the Fell Block CEOP is terminated in the exploitation phase, we will have to obligations under the concession agreement (subject to a cure period). transfer to Chile, free of charge, any productive wells and related facilities, Administrative or monetary sanctions may also be applicable, as determined provided that such transfer does not interfere with our abandonment by the ANP, which shall be imposed based on applicable law and regulations. obligations and excluding certain pipelines and other assets. See “Item 4. In the event of early termination of a concession agreement, the Information on the Company-B. Business overview-Significant agreements- compensation to which we are entitled may not be sufficient to compensate Chile-CEOPs-Fell Block CEOP.” If the CEOP is terminated early due to a breach of us for the full value of our assets. Moreover, in the event of early termination of our obligations, we may not be entitled to compensation. Additionally, our any concession agreement due to failure to fulfill obligations thereunder, we CEOPs for the Tierra del Fuego Blocks, which are in the exploration phase, may may be subject to fines and/or other penalties. be subject to early termination during this phase under circumstances including (i) a failure by us to comply with minimum work commitments at the In Peru, License Contracts for hydrocarbon exploitation are in force and will termination of any exploration period, (ii) a failure to communicate our remain in effect for 30 years. This term is non-renewable. With regards to the intention to proceed with the next exploration period 30 days prior to its Morona Block, currently one-third of the contract term has already elapsed, termination, (iii) a failure to provide the Chilean Ministry of Energy requisite and twenty years remain. Nevertheless, since November 27, 2013, the License performance bonds, (iv) a voluntary relinquishment by us of all areas under the Contract related to the Morona Block is under force majeure. During a force CEOP, (v) a failure by us to meet the requirements to enter into the exploitation majeure period contract terms are suspended (including the term time) as phase upon the termination of the exploration phase, and (vi) a permanent long as the party to the contract is fulfilling certain obligations related to suspension by us of all operations in the CEOP area or our declaration of obtaining environmental permits, as is currently the case with the Morona bankruptcy. If the Tierra del Fuego Block CEOPs are terminated within the Block. The term of the agreement will be extended by the same amount of exploration phase, we are released from all obligations under the CEOPs, time it has been suspended by a force majeure event. The concession year except for obligations regarding the abandonment of fields, if any. See “Item 4. expiration is related to approval of environmental impact assessment (EIA) GeoPark 47 study for project development. The expiration of concession will occur twenty premium over the current gas price for deliveries exceeding certain volumes years after EIA approval. We expect the EIA to be approved in approximately of gas, since the Methanex plant’s startup, which occurred on September 27, December 2018. The License Contract is also subject to early termination in 2015. See “Item 4. Information on the Company-B. Business overview- case of our breach of contractual obligations. In such an event, all the existing Marketing and delivery commitments-Chile.” Methanex made investments facilities and wells located in the block will be transferred, without charge, to aimed at lowering its plant’s minimum gas requirements during the idling, so Perupetro, and we will have to carry out abandonment plans for remediation that the plant is currently able to function with 21.2 mcfpd of gas. and restoration of any polluted area in the block and for de-commission the facilities that are no longer required for the block’s operations. However, we cannot be sure that Methanex will continue to purchase the Early termination or nonrenewal of any CEOP, E&P Contract or concession successful, which could have a material adverse effect on our gas revenues. agreement could have a material adverse effect on our business, financial Additionally, we cannot be sure that Methanex will have sufficient supplies gas from us or that its efforts to reduce the risk of future shut-downs will be situation or results of operations. of gas to operate its plant and continue to purchase our gas production or that methanol prices would be sufficient to cover the operating costs. If We sell almost all of our natural gas in Chile to a single customer, who has in Methanex were to cease purchasing from us, we cannot be sure that we the past temporarily idled its principal facility. would be able to sell our gas production to other parties or on similar terms, which could have a material adverse effect on our business, financial For the year ended December 31, 2015, almost all of our natural gas sales in condition and results of operations. Chile were made to Methanex under a long-term contract, the Methanex Gas Supply Agreement, which expires on April 30, 2017. Sales to Methanex We may not be able to meet delivery requirements under the agreement for represented 7% of our consolidated revenues for the year ended December the sale of our natural gas in Chile. 31, 2015. Methanex also buys gas from ENAP and a consortium that Methanex has formed with ENAP. While our contract with Methanex requires it to Under the Methanex Gas Supply Agreement, Methanex has contracted to purchase the entirety of our production of natural gas from the Fell Block, and purchase all of the gas that we produce in the Fell Block with a minimum requires us to sell to Methanex all of our natural gas production from Fell volume commitment that we define on an annual basis. The agreement Block, subject to minor exceptions, if Methanex were to decrease or cease its contains monthly deliver-or-pay (“DOP”) obligations, which require us to purchase of gas from us, this would have a material adverse effect on our deliver the minimum gas committed for each month or pay a deficiency revenues derived from the sale of gas. In addition, there can be no assurance penalty to Methanex. The agreement also contains monthly take-or-pay that we will be able to extend or renew our contract with Methanex past April (“TOP”) obligations, which apply when our committed volume for a given 30, 2017, which could have a material adverse effect on our business, financial month exceeds 35.3 mcfpd and require Methanex to take in such months the condition and results of operations. minimum gas volume committed for such period or face higher TOP obligations in later months. The threshold for DOP and TOP obligations is 90% Methanex has two methanol producing facilities at its Cabo Negro production of the committed quantities. The DOP and TOP obligations are subject to facility, near the city of Punta Arenas in southern Chile. However, after Argentine make-up provisions without penalty for any delivery or off-take deficiencies natural gas producers cut off exports to Chile in 2007, Methanex had to stop accrued in the three months following the month where delivery or off-take production at all but one of these facilities, and began to rely on local suppliers requirements were not met. of natural gas, including ENAP, for its operations. Since 2009, however, the amount of natural gas that ENAP has been able to provide to Methanex has On May 1, 2015, we executed a sixth amendment to the Gas Supply been decreasing. Although we sell all the natural gas we produce in the Fell Agreement with Methanex, valid until April 30, 2017, which defined new Block to Methanex, and supplied approximately 40-50% of all the natural gas conditions for May 2015 to April 2016 and for May 2016 to April 2017. The sixth consumed by Methanex before the idling of its plant in May 2015, we alone amendment also waived the DOP and TOP thresholds for both parties with cannot supply Methanex with all the natural gas it requires for its operations. reasonable efforts to take and deliver and gave our gas first priority over any third party supplies to Methanex. The plant was idled due to an anticipated insufficient supply of natural gas. The supply of natural gas decreased during the winter months of 2015 due to Though the sixth amendment waived the DOP and TOP thresholds for both the increase in seasonal gas demand from the city of Punta Arenas, to which parties, such clauses or new clauses introduced in further amendments may gas producers, including us, gave priority, delivering gas to the city through apply for periods beyond the ones mentioned above. For example, in 2012, we Methanex which re-sold our gas to ENAP. Methanex continued to purchase failed to meet the adjusted volume obligation for each month from April to from us the volume of gas we produced during the idling, and we signed an December of 2012 and accrued US$1.7 million in DOP payments owed to amendment to the agreement, pursuant to which Methanex pays us a Methanex under the Methanex Gas Supply Agreement. 48 GeoPark 20F We may not be able to meet delivery requirements under the crude sale 25% working interest. Petroperu will also have the right to increase its working agreements in Colombia. interest in the Block by up to 50%, subject to us recovering our investments in the Block through certain agreed terms. See “Item 4. Information on the Company-B. We historically sold to several customers in Colombia, including sales made Business overview-Our operations-Operations in Peru-Morona Block.” through wellhead or pipeline. For 2016 and beyond, we expect to sell most of our Colombian production under long-term agreements with Trafigura and BP. In addition, the terms of the joint venture agreements or association The Trafigura offtake contract began on March 2016 and the BP sales contract agreements governing our other partners’ interests in almost all of the blocks is expected to start by July 2016, but is conditioned on an expansion project of that are not wholly-owned or operated by us require that certain actions be the Ocensa pipeline (“The P135 expansion project”). approved by supermajority vote. The terms of our other current or future license or venture agreements may require at least the majority of working Under the Trafigura Agreement, we agreed on certain priorities for the volumes interests to approve certain actions. As a result, we may have limited ability to to be transported through the Oleoducto de Los Llanos pipeline (“ODL Pipeline”) exercise influence over operations or prospects in the blocks operated by our in the Llanos Basin. For the first period of the agreement, beginning on March 1, partners, or in blocks that are not wholly-owned or operated by us. A breach of 2016 to February 2017, Trafigura will receive 10,000 bopd of our production. Once contractual obligations by our partners who are the operators of such blocks deliveries of the BP agreement start (expected in July 2016), our delivery priorities could eventually affect our rights in exploration and production contracts in will be in the following order: (1) Trafigura’s 5,000 bopd, (2) BP’s 5,000 bopd and our blocks in Colombia. Our dependence on our partners could prevent us (3) all of the production in excess of the aforementioned to Trafigura. For the from realizing our target returns for those discoveries or prospects. second period, from February 2017 to April 2018, any additional volumes will be included in a tender offer. Nonperformance of our obligations of delivery to Moreover, as we are not the sole owner or operator of all of our properties, we Trafigura in terms, amounts and quality of the crude leads us to pay Trafigura’s may not be able to control the timing of exploration or development activities fare commitments in the ODL Pipeline for the transport, dilution and download or the amount of capital expenditures and may therefore not be able to carry of crude, and may lead to early termination of the crude sales agreement as well out our key business strategies of minimizing the cycle time between as the immediate repayment of any amounts outstanding under the prepayment discovery and initial production at such properties. The success and timing of agreement of up US$100 million, as well as compensation for other damages. exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including: On the other hand, the sales contract with BP requires that we deliver 5,000 • the timing and amount of capital expenditures; bopd of our production for a term of 3 years. Nonperformance of the required • the operator’s expertise and financial resources; delivery commitments is penalized with a 3.50 US$/bbl fare for every barrel • approval of other block partners in drilling wells; not shipped below 5,000 bopd. • the scheduling, pre-design, planning, design and approvals of activities We are not, and may not be in the future, the sole owner or operator of all of • selection of technology; and our licensed areas and do not, and may not in the future, hold all of the • the rate of production of reserves, if any. working interests in certain of our licensed areas. Therefore, we may not be and processes; able to control the timing of exploration or development efforts, associated This limited ability to exercise control over the operations on some of our costs, or the rate of production of any non-operated and, to an extent, any license areas may cause a material adverse effect on our financial condition non-wholly-owned, assets. and results of operations. As of December 31, 2015, we are not the operator of the Llanos 17 and Llanos LGI, our strategic partner in Chile and Colombia, may not consent to our 32 blocks in Colombia, which represented 3% of our total production as of taking certain actions or may eventually decide to sell its interest in our December 31, 2015. In Brazil, we are not the operator of the BCAM-40 Chilean and Colombian operations to a third party. Concession, which represented approximately 16% of our total production for the year ended December 31, 2015. We have a strategic partnership with LGI, which has a 20% equity interest in GeoPark Chile S.A., (a sociedad anónima cerrada incorporated under the laws In Chile we are not the sole owner of the Tranquilo, Isla Norte, Campanario and of Chile; hereinafter “GeoPark Chile”), a 14% direct equity interest in GeoPark Flamenco blocks. In Colombia we are not the sole owner of the Llanos 34, TdF S.A. (“GeoPark TdF”) (31.2% taking into account direct and indirect CPO-4, and Abanico blocks. participation through GeoPark Chile) and a 20% equity interest in GeoPark Colombia SAS, through its equity interest in GeoPark Colombia Coöperatie. In Peru we will not be the sole owner of the Morona Block, as we are expected to Our shareholders’ agreements with LGI in each of Chile and Colombia provides assume a 75% working interest of the Morona Block, with Petroperu retaining a that we have a right of first offer if LGI decides to sell any of its interest in GeoPark 49 GeoPark Chile or GeoPark Colombia Coöperatie. There can be no assurance, One of our principal business strategies includes acquisitions of properties, however, that we will have the funds to purchase LGI’s interest in Chile and/or prospects, reserves and leaseholds and other strategic transactions, including Colombia and that LGI will not decide to sell its shares to a third party whose in jurisdictions in which we do not currently operate. The successful interests may not be aligned with ours. acquisition and integration of producing properties, including our acquisitions In addition, our shareholders’ agreements with LGI in Chile and Colombia contain pending Morona Block Acquisition, requires an assessment of several factors, of Winchester, Luna and Cuerva in Colombia, our Brazil Acquisitions and provisions that require GeoPark Chile and GeoPark Colombia Coöperatie, the sole including: shareholder of GeoPark Colombia SAS, to obtain LGI’s consent before • recoverable reserves; undertaking certain actions. For example, under the terms of the shareholders’ • future oil and natural gas prices; agreement with LGI in Colombia, LGI must approve GeoPark Colombia’s annual • development and operating costs; and budget and work programs and mechanisms for funding any such budget or • potential environmental and other liabilities. program, the entering into any borrowings other than those provided in an approved budget or incurred in the ordinary course of business to finance The accuracy of these assessments is inherently uncertain. In connection with working capital needs, the granting of any guarantee or indemnity to secure these assessments, we perform a review of the subject properties that we liabilities of parties other than those of our Colombian subsidiary and disposing believe to be generally consistent with industry practices. Our review and the of any material assets other than those provided for in an approved budget and review of advisors and independent reserves engineers will not reveal all work program. Similarly, in Chile, pursuant to the terms of our shareholders’ existing or potential problems nor will it permit us or them to become agreements with LGI, LGI’s consent is required in order for GeoPark Chile or sufficiently familiar with the properties to fully assess their deficiencies and GeoPark TdF, as applicable, to be able to take certain actions, including: making potential recoverable reserves. Inspections may not always be performed on any decision to terminate or permanently or indefinitely suspend operations in every well, and environmental conditions are not necessarily observable even or surrender our blocks in Chile (other than as required by law or under the terms when an inspection is undertaken. We, advisors or independent reserves of the relevant CEOP for such blocks); selling our blocks in Chile to our affiliates; engineers may apply different assumptions when assessing the same field. making any change to the dividend, voting or other rights that would give Even when problems are identified, the seller may be unwilling or unable to preference to or discriminate against the shareholders of these companies; provide effective contractual protection against all or part of the problems. We entering into certain related party transactions; and creating a security interest often are not entitled to contractual indemnification for environmental over our blocks in Chile (other than in connection with a financing that benefits liabilities and acquire properties on an “as is” basis. Even in those circumstances our Chilean subsidiaries). in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill its contractual Additionally, pursuant to our agreements with LGI in Chile, we and LGI have obligations. There can be no assurance that problems related to the assets or agreed to vote our common shares or otherwise cause GeoPark Chile or management of the companies and operations we have acquired, such as in GeoPark TdF, as the case may be, to declare dividends only after allowing for Colombia or Brazil, or other companies or operations we may acquire in future, retentions of cash to meet anticipated future investments, costs and will not arise in future, and these problems could have a material adverse obligations, and pursuant to our agreement with LGI in Colombia, we and LGI effect on our business, financial condition and results of operations. have agreed to vote our common shares or otherwise cause GeoPark Colombia Coöperatie to declare dividends only after allowing for retentions of Significant acquisitions and other strategic transactions may involve other cash for approved work programs and budgets capital adequacy risks, including: requirements, working capital requirements, banking covenants associated • diversion of our management’s attention to evaluating, negotiating and with any loan entered into by GeoPark Colombia Coöperatie and GeoPark integrating significant acquisitions and strategic transactions; Colombia SAS and operational requirements. Our inability or failure to obtain • challenge and cost of integrating acquired operations, information LGI’s consent or a delay by LGI in granting its consent may restrict or delay the management and other technology systems and business cultures with those ability of GeoPark Chile, GeoPark TdF or GeoPark Colombia to take certain of ours while carrying on our ongoing business; actions, which may have an adverse effect on our operations in such countries • contingencies and liabilities that could not be or were not identified during and on our business, financial 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 If we fail to realize the benefits we anticipate from an acquisition, our results of results, including impairment of goodwill and other intangible assets. operations may be adversely affected. 50 GeoPark 20F It is also possible that we may not identify suitable acquisition targets or strategic estimated discounted future net revenues from our proved reserves on the 12 investment, partnership or alliance candidates. Our inability to identify suitable month unweighted arithmetic average of the first-day-of-the-month price for acquisition targets, strategic investments, partners or alliances, or our inability to the preceding 12 months. Actual future net revenues from our oil and natural complete such transactions, may negatively affect our competitiveness and gas properties will be affected by factors such as: growth opportunities. Moreover, if we fail to properly evaluate acquisitions, • actual prices we receive for oil and natural gas; alliances or investments, we may not achieve the anticipated benefits of any such • actual cost of development and production expenditures; transaction and we may incur costs in excess of what we anticipate. • the amount and timing of actual production; and • changes in governmental regulations, taxation or the taxation invariability Future acquisitions financed with our own cash could deplete the cash and provisions in our CEOPs. working capital available to adequately fund our operations. We may also finance future transactions through debt financing, the issuance of our equity The timing of both our production and our incurrence of expenses in securities, existing cash, cash equivalents or investments, or a combination of connection with the development and production of oil and natural gas the foregoing. Acquisitions financed with the issuance of our equity securities properties will affect the timing and amount of actual future net revenues could be dilutive, which could affect the market price of our stock. from proved reserves, and thus their actual value. In addition, the 10% Acquisitions financed with debt could require us to dedicate a substantial discount factor we use when calculating discounted future net revenues portion of our cash flow to principal and interest payments and could subject may not be the most appropriate discount factor based on interest rates in us to restrictive covenants. effect from time to time and risks associated with us or the oil and natural gas industry in general. The PN-T-597 Concession Agreement in Brazil may not close. In Brazil, GeoPark Brasil is a party to a class action filed by the Federal may require higher levels of capital expenditures than we currently Prosecutor’s Office regarding a concession agreement of exploratory Block anticipate. Therefore, our proved undeveloped reserves ultimately may not The development of our proved undeveloped reserves may take longer and PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and gas be developed or produced. bidding round held in November 2013. The Brazilian Federal Court issued an injunction against the ANP and GeoPark Brasil in December 2013 that As of December 31, 2015, only approximately 32% of our net proved reserves prohibited GeoPark Brasil’s execution of the concession agreement until the are developed (or 33% including the Morona Block in Peru). Development of ANP conducted studies on whether drilling for unconventional resources would our undeveloped reserves may take longer and require higher levels of capital contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark expenditures than we currently anticipate. Additionally, delays in the Brasil, at the instruction of the ANP, signed the concession agreement, which development of our reserves or increases in costs to drill and develop such included a clause prohibiting GeoPark Brasil from conducting unconventional reserves will reduce the standardized measure value of our estimated proved exploration activity in the area. Despite the clause containing the prohibition, undeveloped reserves and future net revenues estimated for such reserves, the judge in the case concluded that the concession agreement should not be and may result in some projects becoming uneconomic, causing the executed. Thus, GeoPark Brasil requested that the ANP comply with the decision quantities associated with these uneconomic projects to no longer be and annul the concession agreement, which the ANP’s Board did on October 9, classified as reserves. This was due to the uneconomic status of the reserves, 2015. The annulment reverted the status of all parties to the status quo ante , given the proximity to the end of the concessions for these blocks, which does which maintains GeoPark Brasil’s right to the block. not allow for future capital investment in the blocks. There can be no assurance that we will not experience similar delays or increases in costs to There is no assurance that we will be able to enter into a concession drill and develop our reserves in the future, which could result in further agreement in the PN-T-597 Block that would be favorable to our exploration reclassifications of our reserves. goals. See “Item 8-Financial Information-A. Consolidated statements and other financial information-Legal proceedings.” We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely The present value of future net revenues from our proved reserves will not affect our cash flow and results of operations. necessarily be the same as the current market value of our estimated oil and natural gas reserves. Our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems You should not assume that the present value of future net revenues from our encountered by our customers could limit our ability to collect amounts owed proved reserves is the current market value of our estimated oil and natural to us, or to enforce the performance of obligations owed to us under gas reserves. For the year ended December 31, 2015, we have based the contractual arrangements. GeoPark 51 The combination of declining cash flows as a result of declines in commodity We are highly dependent on certain members of our management and prices, a reduction in borrowing basis under reserves-based credit facilities technical team, including our geologists and geophysicists, and on our and the lack of availability of debt or equity financing may result in a ability to hire and retain new qualified personnel. significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us. The ability, expertise, judgment and discretion of our management and our technical and engineering teams are key in discovering and developing oil Furthermore, some of our customers may be highly leveraged, and, in any and natural gas resources. Our performance and success are dependent to a event, are subject to their own operating expenses. Therefore, the risk we face large extent upon key members of our management and exploration team, in doing business with these customers may increase. Other customers may and their loss or departure would be detrimental to our future success. In also be subject to regulatory changes, which could increase the risk of addition, our ability to manage our anticipated growth depends on our ability defaulting on their obligations to us. Financial problems experienced by our to recruit and retain qualified personnel. Our ability to retain our employees is customers could result in the impairment of our assets, a decrease in our influenced by the economic environment and the remote locations of our operating cash flows and may also reduce or curtail our customers’ future use exploration blocks, which may enhance competition for human resources of our products and services, which may have an adverse effect on our where we conduct our activities, thereby increasing our turnover rate. There is revenues and may lead to a reduction in reserves. strong competition in our industry to hire employees in operational, technical We may not have the capital to develop our unconventional oil and gas where we operate and throughout Latin America generally. The loss of any of and other areas, and the supply of qualified employees is limited in the regions resources. our executive officers or other key employees of our technical team or our inability to hire and retain new qualified personnel could have a material We have identified opportunities for analyzing the potential of unconventional oil adverse effect on us. and gas resources in some of our blocks and concessions. Our ability to develop this potential depends on a number of factors, including the availability of capital, We and our operations are subject to numerous environmental, health and seasonal conditions, regulatory approvals, negotiation of agreements with third safety laws and regulations which may result in material liabilities and costs. parties, commodity prices, costs, access to and availability of equipment, services and personnel and drilling results. In addition, as we have no previous experience We and our operations are subject to various international, foreign, federal, state in drilling and exploiting unconventional oil and gas resources, the drilling and and local environmental, health and safety laws and regulations governing, exploitation of such unconventional oil and gas resources depends on our ability among other things, the emission and discharge of pollutants into the ground, to acquire the necessary technology, to hire personnel and other support needed air or water; the generation, storage, handling, use, transportation and disposal for extraction or to obtain financing and venture partners to develop such of regulated materials; and human health and safety. Our operations are also activities. Because of these uncertainties, we cannot give any assurance as to the subject to certain environmental risks that are inherent in the oil and gas timing of these activities, or that they will ultimately result in the realization of industry and which may arise unexpectedly and result in material adverse proved reserves or meet our expectations for success. effects on our business, financial condition and results of operations. Breach of Our operations are subject to operating hazards, including extreme weather use of such resources, could result in environmental administrative events, which could expose us to potentially significant losses. investigations and/or lead to the termination of our concessions and contracts. environmental laws, as well as impacts on natural resources and unauthorized Other potential consequences include fines and/or criminal or civil Our operations are subject to potential operating hazards, extreme weather environmental actions. For instance, non-governmental organizations seeking conditions and risks inherent to drilling activities, seismic registration, to preserve the environment may bring actions against us or other oil and gas exploration, production, development and transportation and storage of crude companies in order to, among other things, halt our activities in any of the oil, such as explosions, fires, car and truck accidents, floods, labor disputes, countries in which we operate or require us to pay fines. Additionally, in social unrest, community protests or blockades, guerilla attacks, security Colombia, recent rulings have provided that environmental licenses are breaches, pipeline ruptures and spills and mechanical failure of equipment at administrative acts subject to class actions that could eventually result in their our or third-party facilities. Any of these events could have a material adverse cancellation, with potential adverse impacts on our E&P Contracts. effect on our exploration and production operations, or disrupt transportation or other process-related services provided by our third-party contractors. We are required to obtain environmental permits from governmental authorities for our operations, including drilling permits for our wells. We have not been and may not be at all times in complete compliance with these permits and the environmental and health and safety laws and regulations to which we are subject. If we violate or fail to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our 52 GeoPark 20F operations. If we fail to obtain, maintain or renew permits in a timely manner Environmental, health and safety laws and regulations are complex and change or at all (such as due to opposition from partners, community or frequently, and have tended to become increasingly stringent over time. Our environmental interest groups, governmental delays or any other reasons) or if costs of complying with current and future climate change, environmental, we face additional requirements due to changes in applicable laws and health and safety laws, the actions or omissions of our partners and third-party regulations, our operations could be adversely affected, impeded, or contractors and our liabilities arising from releases of, or exposure to, regulated terminated, which could have a material adverse effect on our business, substances may adversely affect our results of operations and financial financial condition or results of operations. Some environmental licenses condition. See “Item 4. Information on the Company-B. Business overview- related to operation of the Manati Field production system and natural gas Health, safety and environmental matters” and “Item 4. Information on the pipeline have expired. However, the operator submitted timely a request for Company-B. Business overview-Industry and regulatory framework.” renewal of those licenses and as such this operation is not in default as long as the regulator does not state its final position on the renewal. Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could We, as the owner, shareholder or the operator of certain of our past, current and increase the future costs of doing business, cause delays or impede our future discoveries and prospects, could be held liable for some or all plans, and materially adversely affect our operations. environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors, Hydraulic fracturing of unconventional oil and gas resources is a process that predecessors or other operators. To the extent we do not address these costs and involves injecting water, sand, and small volumes of chemicals into the liabilities or if we do not otherwise satisfy our obligations, our operations could wellbore to fracture the hydrocarbon-bearing rock thousands of feet below be suspended, terminated or otherwise adversely affected. We have also the surface to facilitate a higher flow of hydrocarbons into the wellbore. We are contracted with and intend to continue to hire third parties to perform services contemplating such use of hydraulic fracturing in the production of oil and related to our operations. There is a risk that we may contract with third parties natural gas from certain reservoirs, especially shale formations. We currently with unsatisfactory environmental, health and safety records or that our are not aware of any proposals in Colombia, Chile, Brazil, or Argentina to contractors may be unwilling or unable to cover any losses associated with their regulate hydraulic fracturing beyond the regulations already in place. However, acts and omissions. Accordingly, we could be held liable for all costs and liabilities various initiatives in other countries with substantial shale gas resources have arising out of the acts or omissions of our contractors, which could have a been or may be proposed or implemented to, among other things, regulate material adverse effect on our results of operations and financial condition. hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, Releases of regulated substances may occur and can be significant. Under or implement temporary or permanent bans on hydraulic fracturing. If any of certain environmental laws and regulations applicable to us in the countries in the countries in which we operate adopts similar laws or regulations, which is which we operate, we could be held responsible for all of the costs relating to something we cannot predict right now, such adoption could significantly any contamination at our past and current facilities and at any third-party increase the cost of, impede or cause delays in the implementation of any waste disposal sites used by us or on our behalf. Pollution resulting from waste plans to use hydraulic fracturing for unconventional oil and gas resources. 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. Environmental laws and regulations also require that wells be plugged and sites be abandoned and As of December 31, 2015, we had US$378.7 million of total indebtedness reclaimed to the satisfaction of the relevant regulatory authorities. We are outstanding on a consolidated basis, which is 100% secured. As of December currently required to, and in the future may need to, plug and abandon sites in 31, 2015, our annual debt service obligation was approximately US$30.5 certain blocks in each of the countries in which we operate, which could result million, which mainly includes the interest payments under the Notes due in substantial costs. 2020 and the credit facility with Itaú BBA International plc. See “Item 5. Operating and Financial Review and Prospects-B. Liquidity and Capital In addition, we expect continued and increasing attention to climate change Resources-Indebtedness.” We are also restricted from entering into financial issues. Various countries and regions have agreed to regulate emissions of arrangements in some circumstances such as in Colombia where LGI must greenhouse gases including methane (a primary component of natural gas) approve GeoPark Colombia’s financial arrangements. See “Item 4. Information and carbon dioxide (a byproduct of oil and natural gas combustion). The on the Company-B. Business overview-Significant agreements-Agreements regulation of greenhouse gases and the physical impacts of climate change in with LGI-LGI Colombia Agreements” for more information. the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products. GeoPark 53 We have also entered into a prepayment agreement with Trafigura, which Although we have implemented internal control procedures to assure the allows us to receive up to US$100 million in advance payments from Trafigura security of our data, we cannot guarantee that these measures will be sufficient on future oil deliveries. Our indebtedness could: for this purpose. The ability of the information technology function to support our business in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected • limit our capacity to satisfy our obligations with respect to our indebtedness, interruptions cannot be fully tested and there is a risk that, if such an event and any failure to comply with the obligations of any of our debt instruments, actually occurs, we may not be able to address immediately the repercussions including restrictive covenants and borrowing conditions, could result in an of a breach. In the event of a breach, key information and systems may be event of default under the agreements governing our indebtedness; unavailable for a number of days leading to an inability to conduct our • require us to dedicate a substantial portion of our cash flow from operations business or perform some business processes in a timely manner. We have to the payments on our indebtedness, thereby reducing the availability of our implemented strategies to mitigate the impact from these types of events. cash flow to fund acquisitions, working capital, capital expenditures and other general corporate purposes; Our employees have been and will continue to be targeted by parties using • place us at a competitive disadvantage compared to certain of our fraudulent “spam” and “phishing” emails to misappropriate information or to competitors that have less debt; • limit our ability to borrow additional funds; introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails sent by us but direct • in the case of our secured indebtedness, lose assets securing such recipients to fake websites operated by the sender of the email or request that indebtedness upon the exercise of security interests in connection with a the recipient send a password or other confidential information through email default; or download malware. Despite our efforts to mitigate “spoof” and “phishing” • make us more vulnerable to downturns in our business or the economy; and emails through education, “spoof” and “phishing” activities remain a serious • limit our flexibility in planning for, or reacting to, changes in our operations or problem that may damage our information technology infrastructure. business and the industry in which we operate. The indenture governing our Notes due 2020 includes covenants restricting dividend payments. For a description, see “Item 5. Operating and Financial Our operations may be adversely affected by political and economic Review and Prospects-B. Liquidity and Capital Resources-Indebtedness-Notes circumstances in the countries in which we operate and in which we may due 2020.” operate in the future. Risks relating to the countries in which we operate As a result of these restrictive covenants, we are limited in the manner in which All of our current operations are located in South America. For the year ended we conduct our business, and we may be unable to engage in favorable December 31, 2015, our operations in Brazil, Chile and Colombia represented business activities or finance future operations or capital needs. At current 16%, 19% and 65%, respectively, of our total production, with our Argentine prices, absent certain customary exceptions, we do not anticipate achieving an operations representing less than 1% of our total production. If local, regional Adjusted EBITDA (as defined in the indenture governing our Notes due 2020) or worldwide economic trends adversely affect the economy of any of the during fiscal year 2016 that would be sufficient enough to allow us to incur countries in which we have investments or operations, our financial condition additional financial indebtedness, other than certain categories and baskets of and results from operations could be adversely affected. permitted debt, as specified in the indenture. Failure to comply with the restrictive covenants included in our Notes due 2020 would not trigger an Oil and natural gas exploration, development and production activities are event of default. subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in Similar restrictions could apply to us and our subsidiaries when we refinance or laws and policies governing operations of foreign-based companies, enter into new debt agreements which could intensify the risks described above. expropriation of property, cancellation or modification of contract rights, Our business could be negatively impacted by security threats, including regulators, foreign exchange restrictions, price controls, currency fluctuations, cybersecurity threats as well as other disasters, and related disruptions. royalty increases and other risks arising out of foreign governmental revocation of consents or approvals, the obtaining of various approvals from sovereignty, as well as to risks of loss due to civil strife, acts of war and Our business processes depend on the availability, capacity, reliability and community-based actions, such as protests or blockades, guerilla activities, security of our information technology infrastructure and our ability to expand terrorism, acts of sabotage, territorial disputes and insurrection. In addition, we and continually update this infrastructure in response to our changing needs. It are subject both to uncertainties in the application of the tax laws in the is critical to our business that our facilities and infrastructure remain secure. countries in which we operate and to possible changes in such tax laws (or the 54 GeoPark 20F application thereof ), each of which could result in an increase in our tax outside the United States or may not be successful in subjecting non-U.S. liabilities. These risks are higher in developing countries, such as those in which persons to the jurisdiction of courts in the United States, which could we conduct our activities. adversely affect the outcome of such dispute. The main economic risks we face and may face in the future because of our The political and economic uncertainty in Brazil along with the ongoing operations in the countries in which we operate include the following: “Lava Jato” investigations regarding corruption at Petrobras may hinder • difficulties incorporating movements in international prices of crude oil and the growth of the Brazilian economy and could have an adverse effect on exchange rates into domestic prices; our business. • the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s or Brazil’s relations with multilateral credit institutions, such as the IMF, will Our Brazilian operations represent approximately 15% of our revenues as of impact negatively on capital controls, and result in a deterioration of the December 31, 2015. The Brazilian economy has been experiencing a slowdown. business climate; GDP growth rates were 7.5%, 3.9%, 1.8%, 2.7%, and 0.1% in 2010, 2011, 2012, • inflation, exchange rate movements (including devaluations), exchange 2013 and 2014, respectively and GDP decreased 1.9% in the first six months of control policies (including restrictions on remittance of dividends), price 2015. Inflation, unemployment and interest rates have increased more recently instability and fluctuations in interest rates; and the Brazilian reais has weakened significantly in comparison to the US$. • liquidity of domestic capital and lending markets; Our results of operations and financial condition may be adversely affected by • tax policies; and the economic conditions in Brazil. • the possibility that we may become subject to restrictions on repatriation of earnings from the countries in which we operate in the future. In addition to the recent economic crisis, protests, strikes and corruption scandals have led to a fall in confidence. Petrobras and certain other Brazilian In addition, our operations in these areas increase our exposure to risks of guerilla activities, social unrest, local economic conditions, political disruption, civil disturbance, community protests or blockades, expropriation, piracy, tribal companies active in the energy and infrastructure sectors are facing investigations by the Securities Commission of Brazil ( Comissăo de Valores Mobiliários ), the U.S. Securities and Exchange Commission (“SEC”), the conflicts and governmental policies that may: disrupt our operations; require Brazilian Federal Police and the Brazilian Federal Prosecutor’s Office in us to incur greater costs for security; restrict the movement of funds or limit connection with corruption allegations (the “Lava Jato” investigations). repatriation of profits; lead to U.S. government or international sanctions; limit Depending on the duration and outcome of such investigations, the access to markets for periods of time; or influence the market’s perception of companies involved may face downgrades from rating agencies, funding the risk associated with investments in these countries. Some countries in the restrictions and a reduction in their revenues. Given the significance of the geographic areas where we operate have experienced, and may experience in companies under investigation, this could adversely affect Brazil’s growth the future, political instability, and losses caused by these disruptions may not prospects and could have a protracted effect on the oil and gas industry. be covered by insurance. Consequently, our exploration, development and production activities may be substantially affected by factors which could Moreover, as a result of strong popular pressure, legal and administrative have a material adverse effect on our results of operations and financial proceedings for the impeachment of the Brazilian President and/or the condition. Peru’s national election for President will take place in April 2016. resignation of the Brazilian President and the Head of the House of We cannot guarantee that current programs and policies that apply to the oil Representatives are under way. The ongoing political crisis could worsen and gas industry will remain in effect. economic conditions in Brazil and adversely affect our results of operations and financial conditions. Our operations may also be adversely affected by laws and policies of the jurisdictions, including Bermuda, Colombia, Chile, Brazil, Peru, Argentina, the The economic and political crises have resulted in the downgrading of the Netherlands and other jurisdictions in which we do business, that affect country’s long-term credit rating by Standard & Poor’s, Moody’s and Fitch foreign trade and taxation, and by uncertainties in the application of, ratings agencies. Further downgrading of Brazil’s ratings by any of these possible changes to (or to the application of ) tax laws in these jurisdictions. agencies may adversely affect the Brazilian economy, state-controlled entities, Changes in any of these laws or policies or the implementation thereof, and such as Petrobras, and our results of operations and financial conditions. uncertainty over potential changes in policy or regulations affecting any of the factors mentioned above or other factors in the future may increase the We depend on maintaining good relations with the respective host volatility of domestic securities markets and securities issued abroad by governments and national oil companies in each of our countries of operation. companies operating in these countries, which could materially and adversely affect our financial position, results of operations and cash flows. The success of our business and the effective operation of the fields in each Furthermore, we may be subject to the exclusive jurisdiction of courts of our countries of operation depend upon continued good relations and GeoPark 55 cooperation with applicable governmental authorities and agencies, controls, income taxes, expropriation of property, environmental legislation or including national oil companies such as ENAP, Ecopetrol and Petrobras. For health and safety, this could have a material adverse effect on our business, instance, for the year ended December 31, 2015, 100% of our crude oil and financial condition and results of operations. condensate sales in Chile were made to ENAP, the Chilean state-owned oil company. In addition, our Brazilian operations in BCAM-40 Concession Additionally, we are dependent on receipt of Colombian government provide us with a long-term off-take contract with Petrobras, the Brazilian approvals or permits to develop the concessions we hold in Colombia. There state-owned company that covers approximately 100% of net proved gas can be no assurance that future political conditions in Colombia will not result reserves in the Manati Field, one of the largest non-associated gas fields in in the Colombian government adopting different policies with respect to Brazil. If we, the respective host governments and the national oil companies foreign development and ownership of oil, environmental protection, health are not able to cooperate with one another, it could have an adverse impact and safety or labor relations. This may affect our ability to undertake on our business, operations and prospects. exploration and development activities in respect of present and future Oil and natural gas companies in Colombia, Chile, Brazil, Peru and Argentina delays in receiving Colombian government approvals, permits or no objection do not own any of the oil and natural gas reserves in such countries. certificates may delay our operations or may affect the status of our properties, as well as our ability to raise funds to further such activities. Any contractual arrangements or our ability to meet contractual obligations. Under Chilean, Colombian, Brazilian, Peruvian and Argentine law, all onshore and offshore hydrocarbon resources in these countries are owned by the Pursuant to Article 20 of the Brazilian Constitution and Article 3 of Law No. respective sovereign. Although we are the operator of the majority of the 9,478, dated as of August 6, 1997, as amended, or the Brazilian Petroleum Law, blocks and concessions in which we have a working and/or economic interest oil, natural gas and hydrocarbon reserves located within the Brazilian territory, and generally have the power to make decisions as how to market the which encompasses onshore and offshore reserves, as well as deposits in the hydrocarbons we produce, the Chilean, Colombian, Brazilian, Peruvian and Brazilian continental shelf, territorial waters and exclusive economic zone, are Argentine governments have full authority to determine the rights, royalties or considered assets of the Brazilian government. Therefore, the concessionaire compensation to be paid by or to private investors for the exploration or owns only the oil and natural gas that it produces under the concession production of any hydrocarbon reserves located in their respective countries. agreements. Oil and natural gas companies in Brazil acquire the exclusive right Under the Chilean Constitution, the state is the exclusive owner of all mineral areas pursuant to concession agreements awarded by the Brazilian and fossil substances, including hydrocarbons, regardless of who owns the government. However, if the Brazilian government were to restrict or prevent land on which the reserves are located. The exploration and exploitation of concessionaires, including us, from exploiting these oil and natural gas reserves, hydrocarbons may be carried out by the state, companies owned by state or or interfere in the sale or transfer of the production, our ability to generate private persons through administrative concessions granted by the President income would be materially adversely affected, which would have a material of Chile by Supreme Decree or by CEOPs executed by the Minister of Energy. adverse effect on our business, financial condition and results of operations. to explore, develop and produce reserves discovered within certain concession Hydrocarbon exploration and exploitation activities are regulated by the Chilean Ministry of Energy. In Chile, a participant is granted rights to explore Companies in the Brazilian oil and natural gas industry also rely primarily on and exploit certain assets under a CEOP. Although the government cannot the public auction process regulated by the ANP to acquire rights to explore unilaterally modify or terminate the rights granted in the CEOP once it is oil and natural gas reserves. While the ANP may offer concessions in certain signed, if a participant fails to complete certain obligations under a CEOP, such basins in future bidding rounds, there is a risk that future bidding rounds may participant may lose the right to exploit certain areas or may be required to not take place or that they do not include desirable locations, since they are return all or a portion of the awarded areas back to Chile. conducted by and under the Brazilian government’s discretion, which could have a material adverse effect on our business, expected results of operations In Colombia, oil and natural gas companies have acquired the exclusive right and financial condition. to explore, develop and produce reserves discovered within certain concession areas, pursuant to concession agreements awarded by the In Peru, oil and gas exploration and production activities are conducted under Colombian government through the ANH or, prior to 2004, entered into with licenses granted by the Peruvian government. We have acquired a license in Ecopetrol. However, a concessionaire owns only the oil and natural gas that it the Morona Block, the effectiveness of which is subject to the approval by the extracts under the concession agreements to which it is a party. If the Peruvian government. Government approval includes Perupetro’s Colombian government were to restrict or prevent concessionaires, including determination that we fulfill all the requirements needed to develop us, from exploiting these oil and natural gas reserves, or otherwise interfere exploration and production activities in the Morona Block and the enactment with our exploration through regulations with respect to restrictions on future of a Supreme Decree by the Peruvian Ministry of Economy and Finance and exploration and production, price controls, export controls, foreign exchange the Peruvian Ministry of Energy and Mines. 56 GeoPark 20F Under our license in the Morona Block, we and Petroperu (our anticipated in November 2012, the government approved new regulations governing the partner in the block) will have the exclusive right to perform exploration and abandonment of mines and oilfield operations that would require us to obtain production activities in such block, and will pay royalties for the hydrocarbons prior approval for new oil wells and could also require us to post a bond in produced in this area. We will own the hydrocarbons produced in the Morona connection with the abandonment or closure of an oil well. Block in accordance with our participation interest in the block. The Colombian hydrocarbons industry is subject to extensive regulation and Our exploration and production activities in the Morona Block will largely be supervision by the government in matters such as the environment, social shaped by the provisions included in the License Contract, and without such responsibility, tort liability, health and safety, labor, the award of exploration contract it is not possible to carry out any oil and gas activity in the Morona Block. and production contracts by the ANH, the imposition of specific drilling and exploration obligations, taxation, foreign currency controls, price controls, In Argentina, jurisdiction over oil and gas activities is now largely vested in the capital expenditures and required divestments. Existing Colombian regulation same provincial states who own the relevant underground oil and gas applies to virtually all aspects of our concessions or E&P Contracts in Colombia. resources. The Federal Executive Branch is still empowered to design and rule The terms and conditions of the agreements with the ANH may vary by fields, federal energy policy and to rule on domestic inter-jurisdictional and basins and hydrocarbons discovered. international oil and gas transportation concessions and has, for example, imposed measures controlling oil and gas investments in the provincial states. We are required, as are all oil companies undertaking exploratory and production Private companies must obtain exploration permits or exploitation concessions activities in Colombia, to pay a percentage of our expected production to the from the provincial states or otherwise enter into certain types of joint venture Colombian government as royalties. The Colombian government has modified or association agreements with provincial state-owned oil and gas companies the royalty program for oil and natural gas production several times in the last 20 in order to undertake exploration and production activities onshore, and must years, as it has modified the regime regulating new contracts entered into with enter into certain types of joint venture or association agreements with the the Colombian government. The royalty regime for contracts being entered into federally-owned oil and gas company, Energía Argentina Sociedad Anónima today for conventional oil is tied to a scale ring-fenced by field starting at 8% for (“ENARSA”), to undertake these activities offshore. Additionally, whereas until production of up to 5,000 mbopd and increases up to 25% for production above 2012, exploration permit and exploitation concession holders had the right to 600,000 mbopd. Royalties for natural gas production of onshore blocks where freely dispose of and market up to 70% of the production they generated, on our assets are located, range between 8% and 25%. Furthermore, production of July 28th, 2012, the publication of Presidential Decree 1277/2012 abrogated unconventional resources discovered as of May 19, 2012 is subject to royalties this right. As of December 31, 2015, our production in Argentina represented equivalent to 60% of the royalties applicable to conventional oil. less than 1% of our total production, though recent regulations affecting the oil and gas industry in Argentina may have an adverse impact on our business, In Brazil, the oil and natural gas industry is subject to extensive regulation and operations and prospects in Argentina. intervention by the Brazilian government in such matters as the award of exploration and production interests, taxation and foreign currency controls. Oil and gas operators are subject to extensive regulation in the countries in Ultimately, those regulations may also address restrictions on production, which we operate. price controls, mandatory divestments of assets and nationalization, expropriation or cancellation of contractual rights. In Chile, rights to exploration and exploitation of a particular area are established in a CEOP. According to article 19, No 24 of the Chilean Under these laws and regulations, there is potential liability for personal injury, Constitution, the President of Chile has the power to determine the terms and property damage and other types of damages. Failure to comply with these conditions for the granting of a particular CEOP. In addition, the CEOP is laws and regulations also may result in the suspension or termination of subject to extensive supervision by the government through the Chilean operations or our being subjected to administrative, civil and criminal Ministry of Energy. The President of Chile may also decide to terminate a CEOP penalties, which could have a material adverse effect on our financial early, though with compensation to the counterparty, and only if the relevant condition and expected results of operations. We expect to also operate in a area is located within an area declared relevant for national security reasons. consortium in some of our concessions, which, under the Brazilian Petroleum Although the government of Chile cannot unilaterally modify the rights granted operator does not maintain the appropriate licenses, the consortium may in the CEOP once it is signed, exploration and exploitation are nonetheless suffer administrative penalties, including fines of R$10 to R$500 million. subject to significant government regulations, such as regulations concerning the environment, tort liability, health and safety and labor, all of which have an In addition, the local content policy, which is a contractual requirement in a impact on our business and operations. Changes in laws and regulations could Brazilian concession agreements, has become a significant issue for oil and have an adverse effect on the costs and timing of our operations. For example, natural gas companies operating in Brazil given the penalties related with Law, establishes joint and strict liability among consortium members. If the GeoPark 57 breaches thereof. The local content requirement will also apply to the Hydrocarbons Law. The federal government is further empowered to design production sharing contract regime. See “Item 4. Information on the and implement federal energy policy and to rule on domestic inter- Company-B. Business overview-Our operations-Operations in Brazil.” jurisdictional and international oil and gas transportation concessions, and has used these powers to establish export restrictions and duties, induce private In Peru, the hydrocarbons industry is also subject to extensive regulation and companies to enter into price stability agreements with the government or supervision by the government in matters such as: environment, health and otherwise impose price control regulations or create incentive programs to safety, labor, imposition of specific development and exploration obligations, promote increased production. Jurisdictional controversies among the federal taxation, and tort liability. There are many supervisors and regulators, for government and the provincial states are not uncommon. example: a) Perupetro, the state-owned company that promotes, negotiates, signs, and supervises exploration and production contracts; b) The Ministry of Significant expenditures may be required to ensure our compliance with Energy and Mines, which is the central and governing body for the Energy, governmental regulations related to, among other things, licenses for drilling Hydrocarbons and Mining Sector, and a part of the Executive Branch; c) The operations, environmental matters, drilling bonds, reports concerning Bureau of Environmental Evaluation and Control - OEFA, which is the operations, the spacing of wells, unitization of oil and natural gas supervisory body that regulates, enforces and oversees the activities accumulations, local content policy and taxation. undertaken related to environmental hydrocarbon issues; d) The Supervisory Body of Private Investment in Energy and Mines - OSINERGMIN, which is the Governmental actions in the countries in which we operate and in which we regulatory, supervisory body that regulates the activities undertaken by legal may operate in the future may adversely affect our business, financial entities and individuals in the hydrocarbons sectors; e) The General Bureau of condition and results of operations. Environmental Health - DIGESA, which is the technical-regulatory body for aspects related to basic sanitation, occupational health, hygienic food, Our business, financial condition and results of operations may be adversely zoonosis and environmental protection; f ) the Ministry of Agriculture, which is affected by actions taken by the Chilean, Colombian, Brazilian, Peruvian or the entity that promotes the development of organized agrarian producers in Argentine governments concerning the economy, including actions aimed at productive chains; and g) The Ministry of Labor and Employment Promotion targeting inflation, interest rates, oil and gas price controls, foreign exchange - MTPE, which is the body governing labor in Peru, responsible for enforcement controls and taxes. of legislation for labor matters. Brazil has in the past periodically experienced high rates of inflation. As The main provisions regarding oil and gas activities are included in the measured by the National Consumer Price Index ( Índice Nacional de Preços ao General Hydrocarbons Law (Law 26,221) (“General Hydrocarbons Law”), and Consumidor Amplo ), Brazil had annual rates of inflation of 6.5% in 2011, 5.8% in several regulations have been enacted in order to develop the provisions 2012, 5.9% in 2013, 6.4 % in 2014 and 10.7% in 2015. Brazil may experience included therein. There are specific regulations for exploration and production, high levels of inflation in the future. Periods of higher inflation may slow the transport, commercialization, storage, refining, distribution by pipelines, etc. rate of growth of the Brazilian economy. Although the long-term off-take Furthermore, the General Hydrocarbons Law and the related tax regulations inflation is likely to increase some of our costs and expenses, and, as a result, foresee that the signing of an oil and gas agreement implies the guarantee may reduce our profit margins and net income. Inflationary pressures could that the tax regime in effect at the date of signature will not be changed also lead to counter-inflationary prices that may harm our business. Any during the life of the contract. This is intended to preserve the economy of the decline in our expected net sales or net income could lead to a deterioration contract covering gas production in the Manati Field is indexed to inflation, contract so that no further tax costs are created for the contractors. The in our financial condition. signing of an agreement for the exploration or exploitation of a block freezes the tax regime in force at the date that the contract is signed for the entire life In Argentina, since 2001, the Argentine government has imposed and of the contract. Taxes covered by this provision are the taxes in which the expanded upon exchange controls and restrictions on the transfer of US$ responsibility rests on the contractor as a taxpayer. outside of Argentina, which substantially limit the ability of companies to retain foreign currency or make payments abroad. If the Argentine The Argentine hydrocarbons industry is also extensively regulated both by government decides once again to tighten the restrictions on the transfer of federal and provincial state regulations in matters including the award of funds, we may be unable to make payments related to the import of products exploration permits and exploitation concessions, investment, royalty, canon, and services, which could have a material adverse effect on us. price controls, export restrictions and domestic market supply obligations. The terms of our exploitation concessions are embodied in Decrees and Additionally, in May 2012, the Argentine government expropriated 51% of Administrative Decisions issued by the Federal Executive Power and YPF’s capital stock owned by Repsol YPF of Spain, and 51% of the capital stock incorporate statutory rights and obligations provided under the General of Repsol YPF Gas owned by Repsol Butano. 58 GeoPark 20F There can be no assurance that future economic, social and political Nacional (“ELN”), paramilitary groups and drug cartels. In the past, guerrillas developments in the countries in which we operate currently or in the future, have targeted the crude oil pipelines, including the Oleoducto Transandino, which are out of our control, may impair our business, financial condition and Caño Limón-Coveñas and Ocensa pipelines, and other related infrastructure results of operations. disrupting the activities of certain oil and natural gas companies. On several occasions guerilla attacks have resulted in unscheduled shut-downs of the Our operations may be affected by tax reforms in the countries in which we transportation systems in order to repair damaged sections and undertake operate and in which we may operate in the future. clean-up activities. These activities, their possible escalation and the effects Our operations may be affected by changes in tax laws in the countries in on the Colombian economy or on our business, which may affect our which we operate and in which we may operate in the future. In 2014 employees or assets. In the context of the political instability, allegations have Colombian and Chilean governments introduced tax reforms. For example, in been made against members of the government for possible ties to guerillas, the fourth quarter 2014, the Colombian government approved tax legislation paramilitary and/or drug trafficking. This situation may have a negative impact increasing the rate of tax applicable to ordinary income from 34% in 2014 to on the credibility of the Colombian government, which could in turn have a 39% for 2015, 40% for 2016, 42% for 2017 and 43% for 2018. In the same negative impact on the Colombian economy or on our business in the future. associated with them have had and may have in the future a negative impact legislation, the Colombian government also instituted a new “wealth tax” payable on the net equity of our Colombia business units at a rate of 1.15% for The Colombian government commenced peace talks with the FARC in August 2014, 1% for 2015 and 0.4% for 2016. See Note 15 to our Consolidated Financial 2012 and ELN in early 2016. Our business, financial condition and results of Statements. With regards to Chile, although our CEOPs have protection against operations could be adversely affected by rapidly changing economic or social tax changes through invariability tax clauses, potential issues may arise on conditions, including the Colombian government’s response to current peace certain aspects not clearly defined in current or future tax reforms. negotiations which may result in legislation that increases our tax burden or that of other Colombian companies. Tensions with neighboring countries may Furthermore, in December 2015, Colombia’s government announced a plan for affect the Colombian economy and, consequently, our results of operations tax reform to be submitted to Congress in March 2016. The main proposed and financial condition. changes included in the project are the following: (1) unification of the income tax and the income tax on equality (enterprise contribution on equality, “CREE” In addition, from time to time, community protests and blockades may arise for its Spanish acronym), resulting in a new income tax rate between 30% and near our operations in Colombia, which could adversely affect our business, 35%; (2) elimination of the net wealth tax; (3) incorporation of a dividend financial condition or results of operations. distribution withholding tax with a rate between 10% and 15%; and (4) increase of VAT rate from 16% to 19%. All of these measures, if approved, will Our operations may be adversely affected by political and economic take effect from the 2017 fiscal year onwards. circumstances in Argentina. In Brazil, the Brazilian government frequently implements changes to tax and Some of our hydrocarbon blocks and management offices are located in social security regimes that may affect us and our customers. These changes Argentina. If local political or economic trends adversely affect the Argentine include changes in prevailing tax and contribution rates and, occasionally, economy, our financial condition and results from operations could be enactment of temporary taxes, the proceeds of which are earmarked for adversely affected. In particular, we face risks in Argentina related to the designated governmental purposes. Some of these changes in tax laws may following: restrictions on Argentina’s energy supplies and an inadequate result in increases in our tax payments, which could materially adversely affect governmental response to such restrictions, which could negatively affect our profitability and increase the prices of our products and services, restrict Argentina’s economic activity; social and political tensions and the our ability to do business in our existing and target markets and cause our governmental response to such tensions; requirements of the Federal General results of operations to suffer. There can be no assurance that we will be able Environmental Law, which requires persons who carry out activities that are to maintain our projected cash flow and profitability following any increase in potentially hazardous to the environment to obtain insurance; and tax taxes applicable to us and to our operations. implications under Argentine law with respect to our incorporation in Bermuda, which may subject our Argentine subsidiaries to higher tax rates. Colombia has experienced and continues to experience internal security issues that have had or could have a negative effect on the Colombian economy. Colombia has experienced internal security issues, primarily due to the activities of guerrillas, including the Revolutionary Armed Forces of Colombia (Fuerzas Armadas Revolucionarias de Colombia or FARC), Ejercito de Liberación GeoPark 59 Risks related to our common shares We have never paid, and do not intend to pay in the foreseeable future, cash dividends on our common shares. Any decision to pay dividends in the future, An active, liquid and orderly trading market for our common shares may not and the amount of any distributions, is at the discretion of our board of develop and the price of our stock may be volatile, which could limit your directors and our shareholders, and will depend on many factors, such as our ability to sell our common shares. results of operations, financial condition, cash requirements, prospects and other factors. Due to losses resulting from the oil price decline, accumulated Our common shares began to trade on the New York Stock Exchange (“NYSE”)on losses amount to US$208.4 million as of December 31, 2015. February 7, 2014, and as a result have a limited trading history. We cannot predict the extent to which investor interest in our company will maintain an active We are also subject to Bermuda legal constraints that may affect our ability to trading market on the NYSE, or how liquid that market will be in the future. pay dividends on our common shares and make other payments. Under the The market price of our common shares may be volatile and may be we may not declare or pay a dividend if there are reasonable grounds for influenced by many factors, some of which are beyond our control, including: believing that we are, or would after the payment be, unable to pay our • our operating and financial performance and identified potential drilling liabilities as they become due or that the realizable value of our assets would locations, including reserve estimates; thereafter be less than our liabilities. We are also subject to contractual • quarterly variations in the rate of growth of our financial indicators, such as restrictions under certain of our indebtedness. Companies Act, 1981 (as amended) of Bermuda (“Bermuda Companies Act”), net income per common share, net income and revenues; • changes in revenue or earnings estimates or publication of reports by equity We are a holding company dependent upon dividends from our subsidiaries, research analysts; • fluctuations in the price of oil or gas; which may be limited by law and by contract from making distributions to us, which would affect our financial condition, including the ability to pay • speculation in the press or investment community; dividends on the common shares. • sales of our common shares by us or our shareholders, or the perception that such sales may occur; • involvement in litigation; • changes in personnel; • announcements by the company; As a holding company, our only material assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal source of revenues and cash flow is distributions from our subsidiaries. Thus, our ability to pay dividends on the common shares will be contingent upon • domestic and international economic, legal and regulatory factors unrelated the financial condition of our subsidiaries. Our subsidiaries are and will be to our performance. separate legal entities, and although they may be wholly-owned or • variations in our quarterly operating results; controlled by us, they have no obligation to make any funds available to us, • volatility in our industry, the industries of our customers and the global whether in the form of loans, dividends, distributions or otherwise. The ability securities markets; • changes in our dividend policy; of our subsidiaries to distribute cash to us is also subject to, among other things, restrictions that are contained in our and our subsidiaries’ financing • risks relating to our business and industry, including those discussed above; (including our Notes due 2020 and GeoPark Brasil’s loan to finance Rio das • strategic actions by us or our competitors; Contas) and joint venture agreements (principally our agreements with LGI), • actual or expected changes in our growth rates or our competitors’ growth rates; availability of sufficient funds in such subsidiaries and applicable state laws • investor perception of us, the industry in which we operate, the investment and regulatory restrictions. Claims of creditors of our subsidiaries generally opportunity associated with our common shares and our future performance; will have priority as to the assets of such subsidiaries over our claims and • adverse media reports about us or our directors and officers; claims of our creditors and stockholders. To the extent the ability of our • addition or departure of our executive officers; subsidiaries to distribute dividends or other payments to us could be limited • change in coverage of our company by securities analysts; in any way, our business, financial condition and results of operations, as well • trading volume of our common shares; as our ability to pay dividends on the common shares, could be materially • future issuances of our common shares or other securities; adversely affected. • terrorist acts; • the release or expiration of transfer restrictions on our outstanding Additionally, we may not be able to fully control the operations and the assets of common shares. our joint ventures and we may not be able to make major decisions or take timely actions with respect to our joint ventures unless our joint venture We have never declared or paid, and do not intend to pay in the foreseeable partners agree. For example, we have entered into shareholder agreements with future, cash dividends on our common shares, and, consequently, your only LGI in Chile and Colombia that limit the amount of dividends that can be opportunity to achieve a return on your investment is if the price of our declared or returned to us, certain aspects related to the management of our stock appreciates. 60 GeoPark 20F Chilean and Colombian businesses, the incurrence of indebtedness, liens and our ability to sell certain assets. See “-Risks relating to our business-LGI, our In addition, interest and principal amounts payable pursuant to debt strategic partner in Chile and Colombia, may not consent to our taking certain obligations denominated in or indexed to US$ are subject to variations in actions or may eventually decide to sell its interest in our Chilean and Colombian the foreign currency exchange rates that could result in a significant operations to a third party.” We may, in the future, enter into other joint venture increase in the amount of the interest and principal payments in respect of agreements imposing additional restrictions on our ability to pay dividends. such debt obligations. Sales of substantial amounts of our common shares in the public market, or Certain shareholders have substantial control over us and could limit the perception that these sales may occur, could cause the market price of your ability to influence the outcome of key transactions, including a our common shares to decline. change of control. We may issue additional common shares or convertible securities in the future, Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief for example, to finance potential acquisitions of assets, which we intend to Executive Officer, Mr. Juan Cristóbal Pavez, director and Cartica Management, continue to pursue. Sales of substantial amounts of our common shares in the LLC (where Mr. Steven J. Quamme, a former director of our Company is public market, or the perception that these sales may occur, could cause the deemed to have shared voting and investment power rights), control market price of our common shares to decline. This could also impair our approximately 47% of our outstanding common shares as of the date of this ability to raise additional capital through the sale of our equity securities. annual report, holding the shares either directly or through privately held Under our memorandum of association, we are authorized to issue up to funds. As a result, these shareholders, if acting together, would be able to 5,171,949,000 common shares, of which 59,535,614 common shares were influence or control matters requiring approval by our shareholders, including outstanding as of December 31, 2015. We cannot predict the size of future the election of directors and the approval of amalgamations, mergers or other issuances of our common shares or the effect, if any, that future sales and extraordinary transactions. They may also have interests that differ from yours issuances of shares would have on the market price of our common shares. and may vote in a way with which you disagree and which may be adverse to Provisions of the Notes due 2020 could discourage an acquisition of us by a preventing or deterring a change of control of our company, could deprive our your interests. The concentration of ownership may have the effect of delaying, third party. stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might ultimately affect the market price Certain provisions of the Notes due 2020 could make it more difficult or more of our common shares. See “Item 7. Major Shareholders and Related Party expensive for a third party to acquire us, or may even prevent a third party Transactions-A. Major shareholders” for a more detailed description of our from acquiring us. For example, upon the occurrence of a fundamental change, share ownership. holders of the Notes due 2020 will have the right, at their option, to require us to repurchase all of their notes at a purchase price equal to 101% of the As a foreign private issuer, we are subject to different U.S. securities principal amount thereof plus any accrued and unpaid interest (including any laws and NYSE governance standards than domestic U.S. issuers. This additional amounts, if any) to the date of purchase. By discouraging an may afford less protection to holders of our common shares, and you acquisition of us by a third party, these provisions could have the effect of may not receive corporate and company information and disclosure depriving the holders of our common shares of an opportunity to sell their that you are accustomed to receiving or in a manner in which you are common shares at a premium over prevailing market prices. accustomed to receiving it. Variations in interest rates and exchange rate on our current and/or future As a foreign private issuer, the rules governing the information that we financing arrangements may result in significant increases in our disclose differ from those governing U.S. corporations pursuant to the borrowing costs. Securities Exchange Act of 1934, as amended (“Exchange Act”). Although we intend to report quarterly financial results and report certain material events, As of December 31, 2015, a part (20%) of our total debt is sensitive to changes we are not required to file quarterly reports on Form 10-Q or provide current in interest rates. At December 31, 2015, the outstanding long-term borrowing reports on Form 8-K disclosing significant events within four days of their affected by variable rates amounted to US$76,178,000, representing 20% of occurrence and our quarterly or current reports may contain less information total long-term borrowings, which was mainly composed of the loan from than required under U.S. filings. In addition, we are exempt from the Section 14 Itaú Bank that has a floating interest rate based on LIBOR (the “Rio das Contas proxy rules, and proxy statements that we distribute will not be subject to Credit Facility”). For more information, see “Item 4. Information on the review by the SEC. Our exemption from Section 16 rules regarding sales of Company-B. Business overview-Marketing and delivery commitments-Brazil,” common shares by insiders means that you will have less data in this regard and Note 3 in our Financial Statements. Consequently, variations in interest than shareholders of U.S. companies that are subject to the Exchange Act. As a rates could result in significant changes in the amount required to cover our result, you may not have all the data that you are accustomed to having when debt service obligations and our interest expense. making investment decisions. For example, our officers, directors and principal GeoPark 61 shareholders are exempt from the reporting and “short-swing” profit recovery required by Section 404(b) of the Sarbanes-Oxley Act. Accordingly, our provisions of Section 16 of the Exchange Act and the rules thereunder with independent registered public accounting firm did not perform an audit of respect to their purchases and sales of our common shares. The periodic our internal control over financial reporting for the fiscal year ended disclosure required of foreign private issuers is more limited than that required December 31, 2015. Had our independent registered public accounting firm of domestic U.S. issuers and there may therefore be less publicly available performed an attestation on our internal control over financial reporting, it is information about us than is regularly published by or about U.S. public possible that their opinion on our internal controls could have differed from companies. See “Item 10. Additional Information-H. Documents on display.” ours which could harm our reputation and share value. As a foreign private issuer, we will be exempt from complying with certain We will continue to incur significantly increased costs and devote corporate governance requirements of the NYSE applicable to a U.S. issuer, substantial management time as a result of operating as a public company. including the requirement that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve Our initial public offering in February 2014 had a transformative effect on us. any equity issuance by us which represents 20% or more of our outstanding We expect to incur significant legal, accounting, reporting and other expenses common shares. As the corporate governance standards applicable to us are as a result of having publicly traded common shares listed on the NYSE. We different than those applicable to domestic U.S. issuers, you may not have the may also continue to incur costs which we have not incurred previously, same protections afforded under U.S. law and the NYSE rules as shareholders including, but not limited to, costs and expenses for directors’ fees, increased of companies that do not have such exemptions. directors and officers insurance, investor relations, and various other costs of a We are an “emerging growth company,” and we cannot be certain if the public company. reduced disclosure requirements applicable to emerging growth companies We also anticipate that we will incur costs associated with corporate will make our common shares less attractive to investors. governance requirements, including requirements under the Sarbanes Oxley Act of 2002, as well as rules implemented by the SEC and NYSE. We expect We are an “emerging growth company,” as defined in the Jumpstart our these rules and regulations to increase our legal and financial compliance Business Startups Act of 2012 (“JOBS Act”), and for as long as we continue to costs and make some management and corporate governance activities more be an “emerging growth company” we may choose to take advantage of time-consuming and costly, particularly after we are no longer an “emerging certain exemptions from various reporting requirements that are applicable to growth company.” These rules and regulations may make it more difficult and other public companies that are not “emerging growth companies,” including, more expensive for us to obtain director and officer liability insurance, and we but not limited to, not being required to comply with the auditor attestation may be required to accept reduced policy limits and coverage or incur requirements of Section 404(b) of the Sarbanes Oxley Act. We cannot predict if substantially higher costs to obtain the same or similar coverage. This could investors will find our common shares less attractive because we will rely on have an adverse impact on our ability to recruit and bring on a qualified these exemptions. If some investors find our common shares less attractive as independent board. a result, there may be a less active trading market for our common shares and our share price may be more volatile. The additional demands associated with being a public company listed on the NYSE may disrupt regular operations of our business by diverting the Under the JOBS Act, emerging growth companies can delay adopting new or attention of some of our senior management team away from revenue- revised accounting standards until such time as those standards apply to producing activities to management and administrative oversight, adversely private companies. We have irrevocably elected not to avail ourselves of this affecting our ability to attract and complete business opportunities and exemption from new or revised accounting standards, and, therefore, we will increasing the difficulty in both retaining professionals and managing and be subject to the same new or revised accounting standards as other public growing our businesses. Any of these effects could harm our business, financial companies that are not emerging growth companies. condition and results of operations. Our internal controls over financial reporting may not be effective which There are regulatory limitations on the ownership and transfer of our could have a significant and adverse effect on our business and reputation. common shares which could result in the delay or denial of any transfers you We have evaluated our internal controls for our financial reporting and have might seek to make. determined our controls were effective for the fiscal year ended December 31, The Bermuda Monetary Authority (“BMA”), must specifically approve all 2015. As long as we qualify as an “emerging growth company” as defined by issuances and transfers of securities of a Bermuda exempted company like us the JOBS Act, we will not be required to obtain an auditor’s attestation report unless it has granted a general permission. We are able to rely on a general on our internal controls in future annual reports on Form 20-F as otherwise permission from the BMA to issue our common shares, and to freely transfer our 62 GeoPark 20F common shares as long as the common shares are listed on the NYSE and/or Bermuda law differs from the laws in effect in the United States and might other appointed stock exchange, to and among persons who are non-residents afford less protection to shareholders. of Bermuda for exchange control purposes. Any other transfers remain subject to approval by the BMA and such approval may be denied or delayed. Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. We are a Bermuda company, and it may be difficult for you to enforce As a Bermuda company, we are governed by our memorandum of association and judgments against us or against our directors and executive officers. bye-laws and Bermuda company law. The provisions of the Bermuda Companies Act, which applies to us, differs in some material respects from laws generally We are incorporated as an exempted company under the laws of Bermuda and applicable to U.S. corporations and shareholders, including the provisions relating substantially all of our assets are located in Colombia, Chile, Argentina, Brazil to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and are expected to be located additionally in Peru once we obtain pending and indemnification of directors. Set forth below is a summary of these provisions, regulatory approval. In addition, most of our directors and executive officers as well as modifications adopted pursuant to our bye-laws, which differ in certain reside outside the United States and all or a substantial portion of the assets of respects from provisions of Delaware corporate law. Our shareholders approved such persons are located outside the United States. As a result, it may be the adoption of new bye-laws which came into effect on February 19, 2014, being difficult or impossible to effect service of process within the United States the date on which the company cancelled admission of its common shares on upon us, or to recover against us on judgments of U.S. courts, including AIM. Because the following statements are summaries, they do not discuss all judgments predicated upon the civil liability provisions of the U.S. federal aspects of Bermuda law that may be relevant to us and our shareholders. securities laws. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violation of U.S. federal securities Interested Directors. Under our bye-laws and the Bermuda Companies Act, a laws because these laws have no extraterritorial application under Bermuda director shall declare the nature of his interest in any contract or arrangement with law and do not have force of law in Bermuda. However, a Bermuda court may the company. Our bye-laws further provide that a director so interested shall not, impose civil liability, including the possibility of monetary damages, on us or except in particular circumstances, be entitled to vote or be counted in the quorum our directors and officers if the facts alleged in a complaint constitute or give at a meeting in relation to any resolution in which he has an interest, which is to his rise to a cause of action under Bermuda law. knowledge, a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of or otherwise in or through the company). A There is no treaty in force between the United States and Bermuda providing director will be liable to us for any secret profit realized from the transaction. In for the reciprocal recognition and enforcement of judgments in civil and contrast, under Delaware law, such a contract or arrangement is voidable unless it commercial matters. As a result, whether a United States judgment would be is approved by a majority of disinterested directors or by a vote of shareholders, in enforceable in Bermuda against us or our directors and officers depends on each case if the material facts as to the interested director’s relationship or interests whether the U.S. court that entered the judgment is recognized by the are disclosed or are known to the disinterested directors or shareholders, or such Bermuda court as having jurisdiction over us or our directors and officers, as contract or arrangement is fair to the corporation as of the time it is approved or determined by reference to Bermuda conflict of law rules. A judgment debt ratified. Additionally, such interested director could be held liable for a transaction from a U.S. court that is final and for a sum certain based on U.S. federal in which such director derived an improper personal benefit. securities laws will not be enforceable in Bermuda unless the judgment debtor had submitted to the jurisdiction of the U.S. court, and the issue of submission Amalgamations, Mergers and Similar Arrangements. Pursuant to the Bermuda and jurisdiction is a matter of Bermuda (not U.S.) law. Companies Act, the amalgamation or merger of a Bermuda company with another company or corporation requires the amalgamation or merger In addition, and irrespective of jurisdictional issues, the Bermuda courts will agreement to be approved by the company’s board of directors and by its not enforce a U.S. federal securities law that is either penal or contrary to shareholders. Shareholder approval is not required where (i) the holding Bermuda public policy. An action brought pursuant to a public or penal law, company and one or more of its wholly-owned subsidiary companies the purpose of which is the enforcement of a sanction, power or right at the amalgamate or merge or (ii) two or more wholly-owned subsidiary companies instance of the state in its sovereign capacity, will not be entertained by a of the same holding company amalgamate or merge. Save for such “short-form” Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, amalgamations or mergers, unless the company’s bye-laws provide otherwise, including certain remedies under U.S. federal securities laws, would not be the approval of 75% of the shareholders voting at such meeting is required to available under Bermuda law or enforceable in a Bermuda court, as they would pass a resolution to approve the amalgamation or merger agreement. The be contrary to Bermuda public policy. quorum for such a meeting must be two persons holding or representing more than one-third of the issued shares of the company. Under our bye-laws, an amalgamation or merger will require the approval of our board of directors and our shareholders by Special Resolution, which is a resolution adopted by 65% GeoPark 63 of more of the votes cast by shareholders who (being entitled to do so) vote in Indemnification of Directors. We may indemnify our directors and officers in person or by proxy at any general meeting of the shareholders in accordance their capacity as directors or officers for any loss arising or liability attaching to with the provisions of the bye-laws and the quorum for any general meeting them by virtue of any rule of law in respect of any negligence, default, breach must be two or more persons, in person or by proxy, representing in excess of of duty or breach of trust of which a director or officer may be guilty in relation 50% of the total of our issued voting shares. Under Bermuda law, in the event of to the company other than in respect of his own fraud or dishonesty. Our an amalgamation or merger of a Bermuda company with another company or bye-laws provide that we shall indemnify our officers and directors in respect corporation, a shareholder of the Bermuda company who did not vote in favor of their acts and omissions, except in respect of their fraud or dishonesty, or to of the amalgamation or merger and who is not satisfied that he has been recover any gain, personal profit or advantage to which such Director is not offered fair value for his shares may, within one month of notice of the legally entitled, and (by incorporation of the provisions of the Bermuda shareholders meeting, apply to the Supreme Court of Bermuda to appraise the Companies Act) that we may advance money to our officers and directors for fair value of those shares. Under Delaware law, with certain exceptions, a the costs, charges and expenses incurred by our officers and directors in merger, consolidation or sale of all or substantially all the assets of a corporation defending any civil or criminal proceedings against them on condition that must be approved by the board of directors and a majority of the issued and the directors and officers repay the money if any allegations of fraud or outstanding shares entitled to vote thereon. Under Delaware law, a shareholder dishonesty is proved against them provided, however, that, if the Bermuda of a corporation participating in certain major corporate transactions may, Companies Act requires, an advancement of expenses shall be made only under certain circumstances, be entitled to appraisal rights pursuant to which upon delivery to the Company of an undertaking, by or on behalf of such such shareholder may receive cash in the amount of the fair value of the shares indemnitee, to repay all amounts if it shall ultimately be determined by final held by such shareholder (as determined by a court) in lieu of the consideration decision that such indemnitee is not entitled to be indemnified for such such shareholder would otherwise receive in the transaction. expenses under our Bye-laws or otherwise. Under Delaware law, a corporation may indemnify a director or officer of the corporation against expenses Shareholders’ Suit. Class actions and derivative actions are generally not (including attorneys’ fees), judgments, fines and amounts paid in settlement available to shareholders under Bermuda law. The Bermuda courts, however, actually and reasonably incurred in defense of an action, suit or proceeding by would ordinarily be expected to permit a shareholder to commence an action reason of such position if such director or officer acted in good faith and in a in the name of a company to remedy a wrong to the company where the act manner he or she reasonably believed to be in or not opposed to the best complained of is alleged to be beyond the corporate power of the company or interests of the corporation and, with respect to any criminal action or illegal, or would result in the violation of the company’s memorandum of proceeding, such director or officer had no reasonable cause to believe his or association or bye-laws. Furthermore, consideration would be given by a her conduct was unlawful. In addition, we have entered into customary Bermuda court to acts that are alleged to constitute a fraud against the indemnification agreements with our directors. minority shareholders or where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it. As a result of these differences, investors could have more difficulty protecting their interests than would shareholders of a corporation incorporated in the When the affairs of a company are being conducted in a manner which is United States. oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply for an order of the Supreme Court of We may become subject to taxes in Bermuda after March 31, 2035, which Bermuda regulating the conduct of the company’s affairs in the future or an may have a material adverse effect on our results of operations. order to purchase the shares of any shareholders by other shareholders or by the company and, in the case of a purchase by the company, for the reduction Under current Bermuda law, we are not subject to tax on income or capital gains. accordingly of the company’s capital, or otherwise. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Our bye-laws contain a provision by virtue of which we and our shareholders Bermuda enacts legislation imposing tax computed on profits, income, any capital waive any claim or right of action that they have, both individually and on our asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, behalf, against any director or officer in relation to any action or failure to take then the imposition of any such tax shall not be applicable to us or to any of our action by such director or officer, including the breach of any fiduciary duty, operations or shares, debentures or other obligations, until March 31, 2035. We except in respect of any fraud or dishonesty of such director or officer. Class could be subject to taxes in Bermuda after that date. This assurance is subject to actions and derivative actions generally are available to shareholders under the provision that it is not to be construed to prevent the application of any tax or Delaware law for, among other things, breach of fiduciary duty, corporate duty to such persons as are ordinarily resident in Bermuda or to prevent the waste and actions not taken in accordance with applicable law. In such actions, application of any tax payable in accordance with the provisions of the Land Tax the court has discretion to permit the winning party to recover attorneys’ fees Act 1967 or otherwise payable in relation to any property leased to us. We are incurred in connection with such action. incorporated in Bermuda as an exempted company and pay annual Bermuda 64 GeoPark 20F Information on the company government fees. In addition, all entities employing individuals in Bermuda are with 8 in production as of December 31, 2015 and a shallow offshore required to pay a payroll tax and there are other sundry taxes payable, directly or concession in Brazil that includes the Manati Field. Our interest in the PN-T-597 indirectly, to the Bermuda government. Neither we nor our Bermuda subsidiaries Block in Brazil is subject to entry into a concession agreement with the ANP employ individuals in Bermuda as at the date of this annual report. and our interest in the Morona Block in Peru is subject to approval by the The transfer of our common shares may be subject to capital gains taxes Peruvian government. pursuant to indirect transfer rules in Chile. We produced a net average of 20,367 boepd during the year ended December 31, 2015, 65%, 19 %, 16% and less than 1% were in Colombia, Chile, Brazil and In September 2012, Chile established “indirect transfer rules,” which impose Argentina, respectively, and of which 74% was oil. As of December 31, 2015, we taxes, under certain circumstances, on capital gains resulting from indirect had net proved reserves of 48.6 mmboe (composed of 75 % oil and 25% transfers of shares, equity rights, interests or other rights in the equity, control natural gas), of which 30.4 mmboe, or 63%, 12.0 mmboe, or 25% and 6.1 or profits of a Chilean entity, as well as on transfers of other assets and mmboe, or 12 %, were in Colombia, Chile and Brazil respectively. Additionally, property of permanent establishments or other businesses in Chile (“Chilean according to the D&M Reserves Report, as of December 31, 2015, the Morona Assets”). As we indirectly own Chilean Assets, the indirect transfer rules would Block in Peru had net proved reserves, of 18.8 mmboe (composed of 100% oil). apply to transfers of our common shares provided certain conditions outside of our control are met. If such conditions were present and as a result the We have built our company around three principal capabilities: indirect transfer rules were to apply to sales of our common shares, such sales would be subject to indirect transfer tax on the capital gain that may be • as an Explorer, which is our ability, experience, methodology and creativity to determined in each transaction. For a description of the indirect transfer rules find and develop oil and gas reserves in the subsurface, based on the best and the conditions of their application see “Item 10. Additional Information-E. science, solid economics and ability to take the necessary managed risks. Taxation-Chilean tax on transfers of shares.” • as an Operator, which is our ability to execute in a timely manner and to have the know-how to profitably drill for, produce, treat, transport and sell our oil ITEM 4. INFORMATION ON THE COMPANY and gas - with the drive and persistence to find solutions, overcome obstacles, A. History and development of the company • as a Consolidator, which is our ability and initiative to assemble the right seize opportunities and achieve results. General 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 We were incorporated as an exempted company pursuant to the laws of the visions and skills to transform and improve value above ground. Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, our shareholders approved a change in our name to GeoPark Limited, effective We believe that our risk and capital management policies have enabled us from July 31, 2013. We maintain a registered office in Bermuda at Cumberland to compile a geographically diverse portfolio of properties that balances House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. Our principal exploration, development and production of oil and gas. These attributes executive offices are located at Nuestra Señora de los Ángeles 179, Las Condes, have also allowed us to raise capital and to partner with premier Santiago, Chile, telephone number +562 2242 9600, and Florida 981, 1st floor, international companies. Finally, we believe we have developed a distinctive Buenos Aires, Argentina, telephone number +5411 4312 9400. Our website is culture within our organization that promotes and rewards partnership, www.geo-park.com. The information on our website does not constitute part entrepreneurship and merit. Consistent with this approach, all of our of this annual report. Our company employees are eligible to participate in our long-term incentive program, which is the Performance-Based Employee Long-Term Incentive Program. See “Item 6. Directors, Senior Management and Employees-B. We are a leading independent oil and natural gas exploration and production Compensation-Equity Incentive Compensation-Performance-Based (“E&P”) company with operations in Latin America and a proven track record Employee Long-Term Incentive Program.” of growth in production and reserves since 2006. We operate in Colombia, Chile, Brazil and to a lesser extent in Argentina. We also plan to expand our In Chile, we are the first and the largest non-state controlled oil and gas footprint to Peru with our pending Morona Block acquisition, which is subject producer. We began operations in 2006 in the Fell Block and have evolved from to approval by the Peruvian government. See “-B. Business Overview-Our having a non-operated, non-producing interest to having a fully-operated and operations-Operations in Peru.” producing asset with 12.0 mmboe of net proved reserves as of December 31, 2015 and average production of 3,834 boepd in 2015. In addition, we operate We have a well-balanced portfolio of assets that includes working and/or five other hydrocarbon blocks in Chile with significant prospective resources, economic interests in 33 hydrocarbons blocks of which 32 are onshore blocks with two of them in production as of December 31, 2015. GeoPark 65 In Colombia, following our successful acquisitions of Winchester, Luna and and strategy. Mr. O’Shaughnessy currently serves as our Chairman and Mr. Park Cuerva in early 2012, we have an asset base of 10 hydrocarbon blocks where currently serves as our Chief Executive Officer and Deputy Chairman, and both we were able to perform an active exploration and development drilling actively contribute to our ongoing operations and business decisions. campaign, which resulted in multiple new oilfield discoveries and to increase average production from 2,965 boepd for the month of April 30, 2012 (the first Our history commenced with the purchase of AES Corporation’s upstream oil full month following our Colombian acquisitions) to 15,510 boepd in the and natural gas assets in Chile and Argentina. Those assets included a fourth quarter of 2015. Total net production in Colombia averaged 13,183 non-operating working interest in the Fell Block in Chile, which at that time boepd in 2015. As of December 31, 2015, we had net proved reserves of 30.4 was operated by ENAP, the Chilean state-owned hydrocarbon company, and mmboe in Colombia, which represents a 23% increase as compared to 24.7 operating working interests in the Del Mosquito, Cerro Doña Juana and Loma mmboe in 2014, mainly resulting from net additions of proved reserves related Cortaderal Blocks in Argentina, which we collectively refer to as the Argentina to new oil fields discovered in the Llanos 34 Block. Blocks. Since 2002, our business has grown significantly. In Brazil, in May 2013, we agreed to acquire Rio das Contas from Panoro Energy In 2006, after demonstrating our technical expertise and committing to an do Brasil Ltda. (a Brazilian limited liability company and a subsidiary of Panoro exploration and development plan, we obtained a 100% operating working Energy ASA, a Norwegian corporation; hereinafter “Panoro”). Rio das Contas, interest in the Fell Block from the Republic of Chile. Also in 2006, the which gave us a 10% working interest in the shallow offshore Manati Field. This International Finance Corporation (“IFC”), a member of the World Bank Group, transaction closed on March 31, 2014. As of December 31, 2015, we had net became one of our principal shareholders, and we listed our common shares on proved reserves of 6.1 mmboe in Manati. Separately, in September 2013, AIM, a market operated by the London Stock Exchange plc, in an initial public November 2013 and October 2015, we participated in bidding rounds 11, 12 offering of common shares outside the United States. Subsequently, in 2008 and and 13 held by the ANP and entered into new concession agreements relating 2009, we issued and sold additional common shares outside the United States. to twelve new concessions in onshore blocks. One of the concessions is still subject to the entry into the concession agreement, on our Round 12 In 2008 and 2009, we continued our growth in Chile by acquiring operating concessions. See “-Our operations-Operations in Brazil.” working interests in each of the Otway and Tranquilo Blocks, and by forming partnerships with Pluspetrol, Wintershall, Methanex and IFC. In July 2014, we were awarded a new exploratory license, the VIM-3 Block, during the 2014 Colombia Bidding Round, carried out by the ANH. We believe In 2010, we formed a strategic partnership with LGI, a Korean conglomerate, to this block has attractive oil and gas exploration potential in a large area within jointly acquire and develop upstream oil and gas projects in Latin America. LGI’s a proven hydrocarbon system. business includes a portfolio of energy and raw material projects, including oil and gas projects in the Middle East and in Southeast and Central Asia. In Peru, in October 2014 we entered into a Joint Investment Agreement and Joint Operating Agreement with Petroperu to acquire an interest in and In 2011, ENAP awarded us the opportunity to obtain operating working operate the Morona Block located in northern Peru. We will assume a 75% interests in each of the Isla Norte, Flamenco and Campanario Blocks in Tierra working interest and Petroperu will retain the remaining 25%. D&M certified del Fuego, Chile, which we refer to collectively as the Tierra del Fuego Blocks, net proved reserves of 18.8 mmboe in the Morona Block as of December 31, and in 2012, jointly with ENAP, we entered into CEOPs with Chile for the 2015, composed of 100% oil. Final closing of this transaction is subject to exploration and exploitation of hydrocarbons within these blocks. approval by the Peruvian government. In Argentina, in August 2014, our consortium with Pluspetrol was awarded two equity interest in GeoPark TdF for US$148.0 million. LGI also provided GeoPark exploration licenses in the Neuquén Basin, Argentina’s largest producing TdF with US$84.0 million in standby letters of credit to partially secure the hydrocarbon basin where we have a 18% non-operating working interest. In US$101.4 million performance bond required by the Chilean government to addition, in July, 2015, we signed a farm-in agreement with Wintershall for a guarantee GeoPark TdF’s obligations with respect to the minimum work 50% working interest in a new block located in the Neuquén Basin, which program under the Tierra del Fuego CEOPs. Our agreement with LGI in the complements our existing acreage in the basin. Tierra del Fuego Blocks allows us to earn back up to 12% equity participation Also in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14% History We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park, who in GeoPark TdF, depending on the success of our operations in Tierra del Fuego. See “Item 10. Additional Information-C. Material contracts.” have over 25 and 35 years of international oil and natural gas experience, In the first quarter of 2012, we moved into Colombia by acquiring three respectively, and who collectively hold approximately 26% of our common privately held E&P companies, Winchester, Luna and Cuerva. These acquisitions shares as of the date of this annual report, and are involved in our operations provided us with an attractive platform in Colombia that includes working 66 GeoPark 20F interests and/or economic interests in 10 blocks located in the Llanos, In July 2015, we signed a farm-in agreement with Wintershall for the CN-V Magdalena and Catatumbo Basins and covering an area of 575,700 gross acres. Block in Argentina. In October 2015, we were awarded four exploratory blocks in the Brazilian ANP Bid Round 13 in the Reconcavo and Potiguar basins. In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia for US$20.1 million, including the assumption of existing debt and the commitment In December 2015, as part of our long term effort to build an upstream to provide additional funding to cover LGI’s share of required future investments platform in Mexico, we participated in the Mexican Bid Round 1.3 with Grupo in Colombia. In addition, our agreement with LGI in Colombia allows us to earn Alfa for onshore projects, however, no blocks were awarded. back up to 12% of equity participation in GeoPark Colombia, depending on the success of our operations in Colombia. See “Item 10. Additional Information-C. See “Item 3. Key Information-D. Risk factors-Risks relating to our business” and Material contracts.”. We believe our partnership with LGI represents a positive “-B. Business overview-Significant agreements-Peru-Morona Block Acquisition” independent assessment and validation of the quality of our Chilean and Colombian asset inventory, the extent of our technical and operational expertise B. Business overview and the ability of our management to structure and effect significant transactions. We are a leading independent oil and natural gas exploration and production (“E&P”), company with operations in Latin America and a proven track record In May 2013, we entered into agreements to expand our operations to Brazil. of growth in production and reserves since 2006. We operate in Colombia, See “-B. Business overview-Our operations-Operations in Brazil.” Chile, Brazil and, to a lesser extent, in Argentina. We may also commence operations in Peru, pending the acquisition of the Morona Block which is In February 2014, we commenced trading on the NYSE and raised US$98 subject to regulatory approvals. million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through We have a well-balanced portfolio of assets that includes working and/or the issuance of 13,999,700 common shares. economic interests in 33 hydrocarbons blocks, 32 of which are onshore blocks, In July 2014, we were awarded a new exploratory license, the VIM-3 Block, shallow-offshore concession in Brazil that includes the Manati Field. We have during the 2014 Colombia Bidding Round, carried out by the ANH. We believe one concession in Brazil, the PN-T-597 Block that is still subject to the entry this block has attractive oil and gas exploration potential in a large area within into the concession agreement by the ANP and the Morona Block, which is a proven hydrocarbon system. subject to approval by the Peruvian government. including 8 in production as of December 31, 2015, as well as an additional In August 2014, Pluspetrol and we were awarded two exploration licenses in We produced a net average of 20,367 boepd during the year ended December the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding 31, 2015, 65%, 19 %, 16% and less than 1% were in Colombia, Chile, Brazil and Round in Argentina. The blocks are located in the Neuquén Basin, Argentina’s Argentina, respectively, and of which 74% was oil. largest producing hydrocarbon basin. In October 2014, we entered into an agreement to expand our footprint into (composed of 75 % oil and 25% natural gas), of which 30.4 mmboe or 63%, Peru (our fifth country platform in Latin America) through the pending 12.0 mmboe or 25% and 6.1 mmboe or 12 %, were in Colombia, Chile and acquisition of Morona Block in a joint venture with Petroperu. The Morona Brazil respectively. Additionally, according to the D&M Reserves Report, as of Block contains the Situche Central oil field, which has been delineated by two December 31, 2015, the Morona Block in Peru had net proved reserves of 18.8 As of December 31, 2015, we had net proved reserves of 48.6 mmboe wells (with short term tests of approximately 2,400 and 5,200 bopd of 35-36° mmboe (composed of 100% oil). API oil each). The expected work program and development plan for the Situche Central oil field is to be completed in three stages. This initial stage We have been able to successfully develop our assets through the drilling of requires an investment of approximately US$140 million to US$160 million 151 out of 211 (72%) exploratory, appraisal and development wells that we and is expected to be completed within 18 to 24 months after closing. The drilled from January 1, 2006 through December 31, 2015 that became transaction is subject to approval by the Peruvian government. According to productive wells. We have grown our business through winning new licenses the D&M Reserves Report, the Morona Block has net proved reserves of 18.8 and acquiring strategic assets and businesses. Since our inception, we have mmboe as of December 31, 2015, composed of 100% oil. supported our growth through our prospect development efforts, drilling In November 2014, we further expanded our portfolio in Colombia through an participants, accessing debt and equity capital markets, developing and agreement with SK Innovation (a subsidiary of SK Group, the Korean integrated retaining a technical team with vast experience and creating a successful energy and petrochemical company) to farm-in to the CPO-4 Block, located in track record of finding and producing oil and gas in Latin America. A key the Llanos Basin. factor behind our success ratio is our experienced team of geologists, program, long-term strategic partnerships and alliances with key industry GeoPark 67 geophysicists and engineers, including professionals with specialized “Item 3. Key Information-D. Risk Factors-Risks relating to our business-The expertise in the geology of Colombia, Chile, Brazil, Argentina and Peru. current oil price crisis has impacted on our operations and corporate strategy,” and “Item 4. Information on the Company-B. Business Oil industry situation and the impact on our operations Overview-2016 Strategy and Outlook.” As a consequence of the oil price decline which started in the second half of 2014 (WTI and Brent, the main international oil price markers, fell by more The following map shows the countries in which we have blocks with working than 60% between August 2014 and March 2016), the Company has and/or economic interests as of December 31, 2015 and also includes our undertaken a decisive cost cutting program to ensure its ability to both pending Morona Block Acquisition. For information on our working interests in maximize the work program and preserve its cash. For more information see each of these blocks, see “-Our assets” below. Colombia Blocks C O L O M B I A Peru Block Morona(1) P E R U B R A Z I L Brazil Blocks POT - T 619 POT - T 620 POT - T 663 POT - T 664 POT - T 665 POT - T 85 POT - T 94 BCAM - 40 (Manati) SEAL - T 268 POT - T 747 POT - T 882 POT - T 93 POT - T 128 PN - T 597(2) P A C I F I C O C E A N A R G E N T I N A A T L A N T I C O C E A N Argentina Blocks Del Mosquito Sierra del Nevado Puelen CN-V C H I L E La Cuerva Llanos 34 Llanos 62 Yamu Llanos 17 Llanos 32 Abanico Jagüeyes VIM - 3 CPO - 04 Chile Blocks Fell Tranquilo Otway Isla Norte Campanario Flamenco (1) Subject to approval from the Peruvian Government. See “-Our operations- Operations in Peru.” (2) The PNT-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.” 68 GeoPark 20F The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2015. Country Colombia Chile Brazil Argentina Total Oil (mmbbl) 30.4 6.0 0.1 - 36.5 Gas (bcf ) - 36.5 36.2 - 72.7 Oil equivalent (mmboe) 30.4 12.0 6.1 - 48.6 For the year ended December 31, 2015 Revenues (in thousands of US$) 131.9 44.8 32.4 0.6 209.7 % Oil 100% 49% 2% - 75% % of total revenues 62.9% 21.4% 15.4% 0.3% 100.0% The following table sets forth the net proved reserves and other data as of and for the year ended December 31, 2015 as estimated in the D&M Reserves Report corresponding to the pending Morona Block. Final closing of this transaction is subject to approval by the Peruvian government. Country Peru Total Oil (mmbbl) 18.8 18.8 Gas (bcf ) - - Oil equivalent (mmboe) 18.8 18.8 Our commitment to growth has translated into a strong compounded annual growth rate (“CAGR”), of 34% for production in the period from 2010 to 2015, as measured by boepd in the table below. For the year ended December 31, 2015 Revenues (in thousands of US$) - - % Oil 100% 100% % of total revenues - - Average net production (mboepd) % oil 2015 20.4 74% 2014 19.7 74% 2013 13.5 82% For the year ended December 31, 2012 11.3 66% 2011 7.6 33% 2010 6.9 28% During the year ended December 31, 2014, Rio Das Contas, whose production is not accounted for in the table above as the transaction closed in March 31, 2014, produced 3.6 mboepd. Had the Manati Field been acquired January 1, 2014, production would have been a net average of 20,557 during the year ended December 31, 2014. GeoPark 69 Average daily production For the year ended December 31, 2015 Brazil Argentina Colombia 13,183 Chile 1,938 48 - 11,380 19,762 13,183 3,835 3,342 7 - 7 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, 2015 Oil production Total crude oil production (bopd) Natural gas production Total natural gas production (mcf/day) Oil and natural gas production Total oil and natural gas production (boed) Our assets According to the D&M Reserves Report, as of December 31, 2015, the blocks in Colombia, Chile, and Brazil in which we have a working interest had 48.6 mmboe of net proved reserves, with 30.4 mmboe, or 63%, 12.0 mmboe, or 25% and 6.1 mmboe, or 13% of such net proved reserves located in Colombia, Chile and Brazil respectively. Additionally, according to the D&M Reserves Report, as of December 31, 2015, the net proved reserves attributable to our pending Morona Block acquisition in Peru were 18.8 mmboe. Final closing of this transaction is subject to approval by the Peruvian government. We produced a net average of 20,367 boepd during the year ended December 31, 2015 of which 65%, 19 %, 16% and less than 1% were in Colombia, Chile, Brazil and Argentina, respectively, and of which 74% was oil. We are the operator of a majority of the blocks in which we have a working interest. Our strengths We believe that we benefit from the following competitive strengths: High quality and diversified asset base built through a successful track record of organic growth and acquisitions Our assets include a diverse portfolio of oil- and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys. According to the D&M Reserves Report, as of December 31, 2015, we had 48.6 mmboe of net proved reserves in Colombia, Chile and Brazil of which 75%, or 36.5 mmboe, was oil, and 25%, or 12.1 mmboe, was gas and of which 32%, or 15.6 mmboe, was net proved developed reserves. Throughout our history, we have delivered continuous growth in our production, and our management team has been able to identify under-exploited assets and turn them into valuable, productive assets. For example, in 2002, we acquired a non-operating working interest in the Fell Block in Chile, which at the time had no material oil and gas production or reserves despite having been actively 70 GeoPark 20F explored and drilled over the course of more than 50 years. Since 2006, when Significant drilling inventory and resource potential from existing asset base we became the operator of the Fell Block, through 2015, we have invested more than US$500 million and drilled approximately 113 wells in the Block, Our portfolio includes large land holdings in high-potential hydrocarbon with 76% of such wells becoming productive during that period. Currently, we basins and blocks with multiple drilling leads and prospects in different are the operator and sole concessionaire of the Fell Block, which, during the geological formations, which provide a number of attractive opportunities year ended December 31, 2015, produced approximately 3,708 boepd. As of with varying levels of risk. Our drilling inventory consists of over 324 identified December 31, 2015, we generated 40% of Chile’s total oil production and 12% drilling locations, and our development plans target locations that provide of its gas production, according to information provided by the Chilean attractive economics and support a predictable production profile. Ministry of Energy. The acquisitions of Winchester, Luna and Cuerva in Colombia in the first and discovered and put into production the new Tilo, Chachalaca and Jacana quarter of 2012 gave us access to exploratory and productive acres across 10 oil fields that contributed to our growth in proved reserves during 2015. blocks in what we believe to be one of South America’s most attractive oil and gas geographies. According to the D&M Reserves Report, as of Our geoscience team continues to identify new potential accumulations and December 31, 2015, the blocks in Colombia in which we have a working expand our inventory of prospects and drilling opportunities. For example, in Colombia, in 2015, we continued drilling on the Llanos 34 Block interest had 30.4 mmboe of net proved reserves, all of which were in oil. Since we acquired Winchester, Luna and Cuerva, we were able to perform an Funding Platform active exploration and development drilling campaign, which resulted in Though the significant decline in oil prices since the end of 2014 significantly multiple new discoveries and to increase average production to 13,183 impacted our revenues and results from operations for the year ended boepd in Colombia in 2015. Also, we have been able to leverage our December 31, 2015, in the past we have historically benefited from consistent technical expertise achieving significant positive results in terms of reduced cash flows and access to debt and equity capital markets, as well as other drilling costs in our multiple new oilfield discoveries, one of which was funding sources, which have provided us in the past with funds to finance our located in the hanging wall of a normal fault, a play type that had not been organic growth and the pursuit of potential new opportunities. We generated successfully tested before in the Llanos basin. US$25.9 million and US$230.7 million in cash from operations in the years ended December 31, 2015 and 2014, respectively, and had US$82.7 million and The acquisition of Rio Das Contas gave us a 10% working interest in the US$127.7 million in cash and cash equivalents as of December 31, 2015 and BCAM-40 Concession, including the shallow-depth offshore Manati and Camarăo Norte Fields, in the Camamu-Almada Basin in the State of Bahia. The Manati Field, which is in the production phase, is operated by Petrobras (with a 35% working interest), the Brazilian national company and the largest 2014, respectively. As of December 31, 2015 we had US$378.7 million of total financial debt with 79% debt maturing in 2020. Our short-term objectives are to preserve cash, see below “-Our long-term strategy.” oil and gas operator in Brazil, in partnership with QGEP (with a 45% working In December 2015, we entered into an offtake and prepayment agreement interest), and Brasoil (with a 10% working interest). See “-Significant with Trafigura. The agreement provides that we sell and deliver a portion of agreements-Brazil-Rio das Contas Quota Purchase Agreement.” Our Rio das our Colombian crude oil production to Trafigura. This will benefit us by (i) Contas acquisition in Brazil provides us with a long-term off-take contract improving crude oil sales prices; (ii) improving operating netbacks by reducing with Petrobras that covers approximately 100% of net proved gas reserves in transportation costs; (iii) simplifying logistics and reducing risks; and (iv) the Manati Field, a valuable relationship with Petrobras and an established improving working capital. Pricing will be determined at future spot market local platform and presence, with a seasoned and experienced geoscience prices, net of transportation costs. The agreement also provides us with and administrative team to manage our Brazilian assets and to seek new prepayment of up to US$100 million from Trafigura, subject to applicable growth opportunities. According to the D&M Reserves Report, as of volumes corresponding to the terms of the agreement, in the form of prepaid December 31, 2015, BCAM-40 Concession had 6.1 mmboe of net proved future oil sales. Funds committed by Trafigura will be made available to us reserves, (composed of approximately 98% natural gas). See “-Our upon request and will be repaid by us through future oil deliveries over the operations-Operations in Brazil.” period of the contract, which is 2.5 years, including a 6-month grace period. In addition, in line with our growth strategy, the pending acquisition of the In December 2015, we entered in a loan agreement with Banco de Chile for Morona Block in Peru will give us a 75% working interest in the Morona Block. US$7 million to finance the start-up of a new Ache gas field in the Fell Block. According to the D&M Reserves Report, as of December 31, 2015, the Morona Block had 18.8 mmboe of net proved reserves, (composed of 100% oil). Final In March 2014, we borrowed US$70.5 million pursuant to a five-year term closing of this transaction is subject to approval by the Peruvian government. variable interest secured loan, secured by the benefits we receive under the See “-Our operations-Operations in Peru.” Purchase and Sale Agreement for Natural Gas with Petrobras, equal to GeoPark 71 6-month LIBOR + 3.9% to finance part of the purchase price of our Rio das In addition, we strive to provide a safe and motivating workplace for Contas acquisition, and funded the remaining amount with cash on hand. In employees in order to attract, protect, retain and train a quality team in the March 2015, we reached an agreement to: (i) extend the principal payments competitive marketplace for capable energy professionals. that were due in 2015 (amounting to approximately US$15 million), which will be divided pro-rata during the remaining principal installments, starting in Our CEO, Mr. James Park, has been involved in E&P projects in Latin America March 2016 and (ii) to increase the variable interest rate equal to the 6-month since 1978. He has been closely involved in grass-roots exploration activities, LIBOR + 4.0%. drilling and production operations, surface and pipeline construction, legal and regulatory issues, crude oil marketing and transportation and capital In February 2014, we commenced trading on the NYSE and raised US$98 raising for the industry. As of December 31, 2015 Mr. Park held 13.2% of our million (before underwriting commissions and expenses), including the outstanding common shares. over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares. Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the oil In February 2013, we issued US$300.0 million aggregate principal amount of December 31, 2015, Mr. O’Shaughnessy held 13.2% of our outstanding and gas business internationally and in North America since 1976. As of 7.50% senior secured notes due 2020 (“Notes due 2020”). The Notes due 2020 common shares. contain incurrence-based limitations on the amount of indebtedness we can incur See “Item 5. Operating and Financial Review and Prospects-Liquidity and Our management and operating team has an average experience in the capital resources-Indebtedness-Notes due 2020-Covenants.” energy industry of approximately 25 years in companies such as Chevron, San Jorge, Petrobras, Total, Pluspetrol, ENAP and YPF, among others. Throughout In 2010, we issued US$133.0 million aggregate principal amount of 7.75% our history, our management and operating team has had success in senior secured notes in the international markets (“Notes due 2015”), which unlocking unexploited value from previously underdeveloped assets. were redeemed following our issuance in 2013 of the Notes due 2020. In addition, as of March 8, 2016, our executive directors, management and In 2007, we obtained financing from Methanex in an amount of US$40 million, employees (excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy structured as a gas pre-sale agreement with a six-year term at an interest rate and Mr. James F. Park) owned approximately 2% of our outstanding common equal to the 6-month LIBOR that is fully repaid as of the date of this annual report. shares, aligning their interests with those of our shareholders and helping In 2006, we completed an initial public offering of our common shares outside “Item 6. Directors, Senior Management and Employees-B. Compensation.” Our the United States on AIM and, in 2008 and 2009, we issued and sold additional founding shareholders are also involved in our daily operations and strategy. retain the talent we need to continue to support our business strategy. See common shares outside the United States. In February 2006, the IFC became a significant shareholder by contributing LGI, provide us with additional funding flexibility to pursue further acquisitions US$10 million. Later that year, we entered into a loan agreement for US$20 million with the IFC, which we have since fully repaid, to partially finance our We benefit from a number of strong partnerships and relationships. In March 2010, Long-term strategic partnerships and strong strategic relationships, such as with investment program. we entered into a framework agreement with LGI to establish a strategic growth partnership to jointly acquire and invest in oil and natural gas projects throughout Highly committed founding shareholders and technical and management Latin America. In May 2011, our partnership with LGI was strengthened by LGI’s teams with proven industry expertise and technically-driven culture acquisition of a 10% equity interest in our existing Chilean operations. In October 2011, LGI acquired an additional 10% equity interest in GeoPark Chile and a 14% Our founding shareholders, management and operating teams have significant equity interest in GeoPark TdF, and agreed to provide additional financial support experience in the oil and gas industry and a proven technical and commercial for the further development of the Tierra del Fuego Blocks. In December 2012, LGI performance record in onshore fields, as well as complex projects in Latin acquired a 20% equity interest in our Colombian business. As of the date of this America and around the world, including expertise in identifying acquisition annual report, we are the only independent E&P company in which LGI has equity and expansion opportunities. Moreover, we differentiate ourselves from other investments in Latin America. See “-Significant agreements-Agreements with LGI” E&P companies through our technically-driven culture, which fosters innovation, for additional information relating to these agreements. creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success of our business strategy, and we have created an In addition, the IFC has been one of our shareholders since 2006, holding an environment and supplied the resources that enable our technical team to focus 5.81% equity interest in us as of December 31, 2015. In Chile, we have strong its knowledge, skills and experience on finding and developing oil and gas fields. long-term commercial relationships with Methanex and ENAP, and in 72 GeoPark 20F Colombia, through our acquisitions of Winchester, Luna and Cuerva, we have Our long-term strategy inherited a strong relationship with Ecopetrol, the Colombian state-owned oil Continue to grow a risk-balanced asset portfolio and gas company. We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential In Brazil, we believe we will continue to derive benefit from the long-term opportunities, and on increasing production and reserves through finding, relationship GeoPark Brasil (formerly Rio Das Contas) has with Petrobras. developing and producing oil and gas reserves in the countries in which we 2016 Strategy and Outlook operate. For example, through our expansion into Brazil, we have secured steady cash flows through our acquisition of Rio das Contas, as well as Our strategic approach to 2016 is guided by the following principles: exploratory potential through our success in three ANP oil and gas bidding • Secure Base: Secure a strong base program for any pricing environment rounds in which we were awarded a total of twelve concessions in Brazil. - prioritizing lower risk, higher netback and fastest cash flow producing projects • Capital Allocation Discipline: Select the best projects out of a large number of In Peru, the pending acquisition of the Morona Block contains the Situche Central oil projects presented by each country based on technical, economic and field, which has been delineated by two wells and geophysical surveys, an operating strategic criteria field camp and logistics infrastructure. In addition to the Situche Central field, the • Work Program Flexibility: Maximize optionality and flexibility to add or Morona Block has a large exploration potential with several high impact prospects reduce projects based on different oil prices and project performance and plays. This important component of the project will significantly increase our • Protect Long Term: Protect key assets, tools and capabilities necessary for overall inventory of exploration resources and complement our growing reserve long-term plan and success and cash flow base already established in Colombia, Chile and Brazil. • Build Scale: Acquire attractive new assets, taking advantage of unique market opportunity In July 2014, we were awarded a new exploratory license, the VIM-3 Block, during the 2014 Colombia Bidding Round, carried out by the ANH. We believe Oil prices have been volatile since the end of 2014 and have remained at low this block has attractive oil and gas exploration potential in a large area within levels in the first part of 2016. In preparation for continued volatility, we a proven hydrocarbon system. developed multiple scenarios for our 2016 capital expenditure program, as stated below: In Argentina, in August 2014, our consortium of with Pluspetrol was awarded two exploration licenses located in the Neuquén Basin, Argentina’s largest Our preliminary base capital program for 2016 considers a reference oil price producing hydrocarbon basin. In addition, in July, 2015, we signed a farm-in assumption of US$35-US$40 per barrel and calls for approximately US$45 agreement with Wintershall for a new block located in Neuquén Basin, million-US$55 million to fund our exploration and development, which we complementing our existing acreage in the basin with world class partners. intend to fund through cash flows from operations and cash-in-hand. In addition, we have developed downside and upside work program scenarios In October 2015, we were awarded four exploratory blocks in the Brazilian ANP based on different oil prices and project performance. The downside scenario Bid Round 13 in the Reconcavo and Potiguar basins. work program considers a reference oil price assumption of US$25-US$30 per barrel and consists of an alternative capital expenditure program of We believe this approach will allow us to sustain continuous and profitable approximately US$20 million-US$25 million consisting mainly of certain low growth and also participate in higher risk growth opportunities with upside risk and quick cash flow generating projects. The upside scenario work potential. See “-Our operations.” program considers a reference oil price assumption of US$50 per barrel or higher and consists of an alternative capital expenditure program of Maintain conservative financial policies approximately US$75 million-US$90 million to be selected from identified We seek to maintain a prudent and sustainable capital structure and a strong projects designed to increase reserves and production. See “Item 3. Key financial position to allow us to maximize the development of our assets and Information-D. Risk factors “The current oil price crisis has impacted our capitalize on business opportunities as they arise. We intend to remain operations and corporate strategy.” financially disciplined by limiting substantially all our debt incurrence to identified projects with repayment sources. We expect to continue benefiting During the first quarter of 2016 we were working under the downside case from diverse funding sources such as our partners and customers in addition scenario, that consisted of drilling two gas wells in Chile. to the international capital markets. If oil prices average higher than the base budget price, we have the ability to Pursue strategic acquisitions in Latin America allocate additional capital to more projects and increase its work and We have historically benefited from, and intend to continue to grow through, investment program and thereby further increase oil and gas production. strategic acquisitions. Our Colombian acquisitions highlight our ability to GeoPark 73 identify and execute opportunities. These acquisitions have provided us with, several international quality standards, including ISO 14001 for and we expect that our Morona Block in Peru, will provide us with an environmental management issues, OHSAS 18001 for occupational health additional attractive platforms in those countries. Our enhanced regional and safety management issues, SA 8000 for social accountability and portfolio, primarily in investment-grade countries, and strong partnerships workers’ rights issues, and applicable World Bank standards. See “-Health, position us as a regional consolidator. We intend to continue to grow through safety and environmental matters.” strategic acquisitions and potentially in other countries in Latin America. Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-risk Our operations cash flow-generating properties and assets that have upside potential, We have a well-balanced portfolio of assets that includes working and/or keeping a balanced mix of oil- and gas-producing assets (though we expect to economic interests in 33 hydrocarbons blocks, 32 of which are onshore blocks, remain weighted towards oil) and focusing on both assets and corporate including 8 in production as of December 31, 2015, as well as in an additional targets. For example, during 2015, as part of our long term effort to build an shallow-offshore concession in Brazil that includes the Manati Field. In upstream platform in Mexico, we participated in the Mexican Bid Round 1.3 addition, we have one concession in Brazil, the PN-T-597 Block that is subject with Grupo Alfa for onshore projects, however, no blocks were awarded. to the entry into the concession agreement by the ANP and the Morona Block in Peru, which is subject to approval by the Peruvian government. Continue to foster a technically-driven culture and to capitalize on local knowledge Operations in Colombia We intend to continue to build and strengthen an environment that will allow Our Colombian assets currently give us access to 1,058,000 of gross us to fully consider and understand risks and rewards and to deliberately and exploratory and productive acres across 10 blocks in what we believe to be collectively pursue strategies that maximize value. For this purpose, we intend one of South America’s most attractive oil and gas geographies. to continue expanding our technical teams and to foster a culture that rewards talent according to results. For example, we have been able to Since we entered Colombia in 2012, we have achieved consistent growth in maintain the technical teams we inherited through our Colombian and our oil production and proved reserves in Colombia, mainly achieved through Brazilian acquisitions. We believe local technical and professional knowledge is successful exploration and development activities we made at our operated key to operational and long-term success and intend to continue to secure Llanos 34 Block. local talent as we grow our business in different locations. Maintain a high degree of operatorship The table below shows average production and proved oil reserves (derived from D&M Reserves Report) in Colombia for the years ended December 31, As of the date of this Annual Report, we are and intend to continue to be, 2015, 2014 and 2013: the operator of a majority of the blocks and concessions in which we have working interests. Operating the majority of our blocks and concessions gives us the flexibility to allocate our capital and resources opportunistically Average net production (mboepd) and efficiently. We believe that this strategy has allowed, and will continue Proved oil reserves at year-end (mmbbl) to allow, us to leverage our unique culture and our talented technical, 2015 13.2 30.4 2014 10.7 24.7 2013 6.5 9.4 operating and management teams. As of December 31, 2015, 86% of our net Highlights of the year ended December 31, 2015 related to our operations in proved reserves and 80% of our production came from blocks in which we Colombia included: are the operator. • Three new oil fields discovered and put into production in Llanos 34 Block: Tilo, Chachalaca and Jacana Maintain our commitment to environmental and social responsibility • Average production increased by 23%, to 13.2 mboepd in 2015 from 10.7 A major component of our business strategy is our focus on our mboepd in 2014 environmental and social responsibility. We are committed to minimizing the • Capital expenditures reduced by 57%, to US$30.7 million in 2015, from impact of our projects on the environment. We also aim to create mutually US$71.4 in 2014 beneficial relationships with the local communities in which we operate in • Proved reserves increased by 23% to 30.4 mmbbls at year-end 2015, from order to enhance our ability to create sustainable value in our projects. In 24.7 mmbbls at year-end 2014 after producing 4.8 mmbbl. line with the IFC’s standards, our commitment to our environmental and social responsibilities is a major component of our business strategy. These Our interests in Colombia include working interests and economic interests. commitments are embodied in our in-house designed Environmental, “Working interests” are direct participation interests granted to us pursuant to Health, Safety and Security management program, which we refer to as an E&P Contract with the ANH, whereas “economic interests” are indirect “S.P.E.E.D.” (Safety, Prosperity, Employees, Environment and Community participation interests in the net revenues from a given block based on Development). Our S.P.E.E.D. program was developed in accordance with bilateral agreements with the concessionaires. 74 GeoPark 20F Under the terms of the agreement to acquire Winchester (“Winchester Stock The map below shows the location of the blocks in Colombia in which we have Purchase Agreement”), we are obligated to make certain payments to the working and/or economic interests. previous owners of Winchester based on the production and sale of hydrocarbons discovered by exploration wells drilled after October 25, 2011. These payments involve both an earnings-based measure and an overriding royalty equal to an estimated 4% of our net revenues for any new discoveries of oil. During 2015, we accrued and paid US$7.1 million and accrued US$9.2 million to the previous owners of Winchester pursuant to the Winchester Stock Purchase Agreement. C A R I B B E A N S E A P A N A M A VIM - 3 V E N E Z U E L A P A C I F I C O C E A N Abanico Llanos 17 Yamu Jagüeyes La Cuerva Llanos 62 Llanos 32 Llanos 34 CPO - 04 C O L O M B I A E C U A D O R P E R U B R A Z I L GeoPark 75 Gross acres (thousand acres) Working interest(1) Partners(2) Operator Net proved reserves (mmboe)(3) Production (boepd) Basin Concession expiration year Exploration: 2014 47.8 100.0% - GeoPark 1.0 389 Llanos Exploitation: 2038 45.0% Parex GeoPark 28.8 11,990 Llanos Exploitation: 2039 Exploration: 2017 - 0.3 - 0.3 - - - - 95 - Exploration: 2017 Llanos Exploitation: 2041 Llanos Exploration: 2013 Production: 2036 Exploration: 2015 Llanos Exploitation: 2039 Exploration: 2015 645 Llanos Exploitation: 2039 Exploration: 2014 Llanos Exploitation: 2038 Exploration: 2021 Magdalena Exploitation: 2045 Exploration: 2015 Llanos Exploitation: 2038 - - - The table summarizes information about the blocks in Colombia in wich we have working interest as of and for the year ended December 31, 2015. Block La Cuerva Llanos 34 Llanos 62 Yamú Llanos 17 Llanos 32 82.2 44.0 11.2 100.0% 89.5/ 100%(4) - - GeoPark GeoPark 108.8 36.8%(5) 100.3 10% Parex APCO; Parex Parex Parex Jagüeyes 3432A 61.0 5.0% Columbus Columbus VIM-3 CPO-4 225.0 100% 345.6 50% - SK GeoPark GeoPark (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 Colombian operations. See “-Significant agreements-Agreements with LGI-LGI Colombia Agreements.” (2) Partners with working interests. (3) As of December 31, 2015. (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 Block. Taking those other parties’ interests into account, we have a 89.5% interest in the Carupana Field and a 100% interest in the Yamú and Potrillo Fields, both located in the Yamú Block. (5) We currently have a 36.8% working interest in the Llanos 17 Block. The table summarizes information about the blocks in Colombia in which we have economic interests as of and for the year ended December 31, 2015. Gross acres (thousand acres) 32.1 Economic interest(1) 10% Block Abanico Production Operator (boepd) Basin Pacific 64 Magdalena (1) Economic interest corresponds to indirect participation interests in the net revenues from the Block, granted to us pursuant to a joint operating agreement. 76 GeoPark 20F Eastern Llanos Basin: (La Cuerva, Yamú, Llanos 34, Llanos 32, Llanos 62, with the ANH. We have committed to drill two exploratory wells before June Llanos 17, Jagüeyes 3432A, Abanico, CPO-4 and VIM-3 Blocks) 2016. The remaining commitment amounts to US$6.0 million. 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, the (Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had Yamú Block, which covers approximately 11,200 gross acres (45.5 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 of parties. In May 2013, we successfully drilled and completed the Potrillo 1 well the Gachetá formation. The main reservoirs of the basin are represented by the in the block to a total depth of 3,560 meters. The well was put in production Paleogene Carbonera and Mirador sandstones. Within the Cretaceous with an initial rate of 744 bopd, from the existing facility at Carupana Field. For sequence, several sandstones are also considered to have good reservoirs. the year ended December 31, 2015, our average net production at the Yamú Block was 95 bopd, which was a result of our by the temporary shut down of Llanos 34 Block. We are the operator of, and have a 45% working interest in, the our operations in this Block. Llanos 34 Block, which covers approximately 82,200 gross acres (333 sq. km). We acquired an interest in and took operatorship of the block in the first quarter of On November 19, 2015, our Colombian subsidiary agreed to terminate the 2012, which at the time had no production, reserves or wells drilled on it, and agreement for its 10% non-operating economic interest in the Cerrito Block for with 210 sq. km of existing 3D seismic on which our team had mapped multiple additional interests held by Trayectoria Oil & Gas in the Yamú Block that exploration prospects. From 2012 to 2014 we engaged in exploration and included a 10% economic interest in all of the Yamú fields by compensation development activities that resulted in 5 new oil fields discovered and increased for pending cash calls and accumulated losses in the Cerrito joint operating production to an average of 8,306 boepd and proved reserves of 21.5 mmboe. agreement. In early 2015, we successfully tested a new well in a new oil field, at Tilo, and Llanos 17 Block. We have a 40% working interest in the Llanos 17 Block, which subsequently drilled and discovered 2 new oil fields at Jacana and Chachalaca. In covers approximately 108,800 gross acres (440 sq. km). Parex is the operator of, and Tilo field there are currently 2 wells in production from the Guadalupe formation has a 60% working interest in, the Llanos 17 Block. Since we acquired a working reservoir with oil of 13.5ºAPI. The Jacana field has 2 wells currently in production interest in the block, two wells have been drilled, one of which was productive. We from the Guadalupe formation reservoir with oil of 15ºAPI. The Chachalaca field is maintain our 40% working interest in the Llanos 17 Block pursuant to an E&P producing from the Mirador formation with oil of 31ºAPI. Average net oil Contract with the ANH. However, we expect to apply to the ANH to approve an production from the Llanos 34 Block in 2015 was 11,990 bopd. We have committed assignment of 3.2% of our working interest in this block to another party. to drill 2 new exploratory wells before September 2017 that will cost US$4.3 million. Llanos 32 Block. We have a 10% working interest in the Llanos 32 Block, which Our partner in the Llanos 34 Block is Parex, which has a 55% interest. See “-Our covers approximately 100,300 gross acres (406 sq. km) Parex is the operator operations.” We operate in the block pursuant to an E&P Contract with the of, and has a 70% working interest in this block. Pluspetrol has a 20% ANH. See “-Significant agreements-Colombia-E&P Contracts-Llanos 34 Block working interest. As of December 31, 2013 four wells have been drilled in the E&P Contract.” block, three of which were productive. In 2014, three additional discoveries were made at fields Kananaskis, Carmentea and Calona in both the Mirador La Cuerva Block. We are the operator of, and have a 100% working interest in, and Une reservoirs, with 7 wells drilled: 4 wells in Kananaskis, 1 well in the La Cuerva Block, which covers approximately 47,800 gross acres (190 sq. Calona, and 2 wells at Carmentea. In 2015 the operator focused on the km). Since we acquired an interest in the La Cuerva Block, we have drilled a commissioning of a gas facility on this block to produce natural gas and light total of 15 wells in the block, 12 of which were productive at year-end 2015. crude oil from the Une formation and to facilitate shipment of processed gas Due to the impact of low oil prices, the block was temporarily shut in the first south to the adjacent Llanos 34 Block. For the year ended December 31, quarter of 2015 and re-opened in the third quarter of 2015 with a more 2015, our average net production in the Llanos 32 Block was 645 bopd. efficient cost structure. For the year ended December 31, 2015, our average net production at the La Cuerva Block was 389 bopd. During the first quarter of Jagüeyes 3432A Block. We have a 5% working interest in the Jagüeyes 3432A 2016 we temporarily shutdown our operations in this block. We operate in the Block, which covers approximately 61,000 acres (247 sq. km). Our partner in the block pursuant to an E&P Contract with the ANH. block is Columbus Energy, who maintains a 95% working interest in and is the operator of the Jagüeyes 3432A Block. The E&P contract with ANH is currently Llanos 62 Block. We are the operator of, and have a 100% working interest in, suspended due to force majeure. the Llanos 62 Block, which covers approximately 44,000 gross acres (178 sq. km). As of December 31, 2014, we had undertaken 72.2sq. km of 3D seismic Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. surveys within the block. We operate the block pursuant to an E&P Contract entered into the Abanico Block association contract. Pacific is the operator of, and GeoPark 77 has a 100% working interest in, the Abanico Block, which covers an area of Our Chilean blocks are located in the provinces of Ultima Esperanza, approximately 32.1 gross acres. We do not maintain a direct working interest in Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil- and the Abanico Block, but rather have a 10% economic interest in the net revenues gas-producing area. As of December 31, 2015, the Magallanes Basin accounted from the block pursuant to a joint operating agreement initially entered into with for all of Chile’s oil and gas production. Although this basin has been in Kappa Resources Colombia Limited (now Pacific, who subsequently assigned its production for over 60 years, we believe that it remains relatively participation interest to Cespa de Colombia S.A., who then assigned the interest underdeveloped. to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A. Substantial technical data (seismic, geological, drilling and production Cerrito Block. In February of 2002, Ecopetrol and Kappa Resources Colombia information), developed by us and by ENAP, provides an informed base for new Limited (now Pacific) entered into the Cerrito Block association contract. The hydrocarbon exploration and development. Shut-in and abandoned fields may Cerrito Block covers an area of approximately 10.2 thousand gross acres. Pacific also have the potential to be put back in production by constructing new is the operator of, and has a 100% working interest in, the Cerrito Block. We do pipelines and plants. Our geophysical analyses suggest additional not maintain a direct working interest in the Cerrito Block, but rather had a development potential in known fields and exploration potential in undrilled 10% economic interest in the block pursuant to a joint operating agreement prospects and plays, including opportunities in the Springhill, Tertiary, Tobífera initially entered into with Kappa Resources Colombia Limited (now Pacific), and Estratos con Favrella formations. The Springhill formation has historically Maral Finance Corporation, Geoproduction Oil & Gas Company of Colombia been the source of production in the Fell Block, though the Estratos con Limitada and Texican Oil PLC. On November 19, 2015, our Colombian subsidiary Favrella shale formation is the principal source rock of the Magallanes Basin, agreed to terminate the joint operating agreement for its 10% non-operating and we believe it contains unconventional resource potential. economic interest in the Cerrito Block for additional interests held by Trayectoria Oil & Gas in the Yamú Block that included a 10% economic interest Highlights of the year ended December 31, 2015 related to our operations in in all of the Yamú fields by compensation for pending cash calls and Chile included: accumulated losses in the Cerrito joint operating agreement. • Construction of a new gas treatment facility that allowed to put the Ache field into production in Fell Block at a rate of approximately 6.7 mmcfpd VIM-3 Block. On July 23, 2014 we were awarded a new exploratory license during • Capital expenditures reduced by 92%, to US$12.4 million in 2015, from the 2014 Colombia Bidding Round, carried out by the ANH. The VIM-3 Block is US$154.3 in 2014 located in the Lower Magdalena Basin, covering an area of approximately 225,000 • Proved oil and gas reserves maintained at 12.0 mmboe at year-end 2015, acres. Our winning bid consisted of committing to a Royalty X Factor of 3% and a from 12.1 mmboe at year-end 2014 after producing 1.4 mmboe. minimum investment program of carrying out 200 sq. km of 2D seismic and drilling one exploratory well, with a total estimated investment of US$22.2 million The map below shows the location of the blocks in Chile in which we have during the initial three-year exploratory period. We will operate and have a 100% working interests. working interest in the block. The block has an attractive oil and gas exploration potential in a large area within a proven hydrocarbon system, surrounded by existing oil and gas fields and with sparse exploration activity carried out to date. CPO-4 Block. In November 2014, we expanded our portfolio in Colombia through an agreement with SK Innovation (subsidiary of SK Group, the Korean integrated energy and petrochemical company) to farm-in to the CPO-4 Block, located in the Llanos Basin. The block covers an area of approximately 345,600 acres with 3D seismic coverage of approximately 880 sq. km. In accordance with the farm-in agreement, and subject to the approval of ANH in Colombia, we will operate and receive a 50% working interest in the CPO-4 Block in exchange for its commitment to drill and fund its 50% (with no carry) of one exploration well. During 2015 we drilled but abandoned the Grulla 1 exploratory well due to an uneconomical discovery of hydrocarbons. Operations in Chile Our Chilean assets currently give us access to 936,000 of gross exploratory and productive acres across 6 blocks in a large fully-operated land base across the Magallanes Basin, with existing reserves, production and cash flows. 78 GeoPark 20F C H I L E A R G E N T I N A Tranquilo Otway 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, 2015. working interests. Block Fell Tranquilo Otway Isla Norte 92.4 49.4(4) 29 %(6) 100 % Pluspetrol Wintershall Methanex - GeoPark GeoPark 130.2 60 %(5) ENAP GeoPark Gross acres (thousand acres) Working interest(1)(6) Partners(2) Operator Net proved reserves (mmboe)(3) Production (boepd) Basin Concession expiration year 367.8 100 % - GeoPark 11.9 3,708 Magallanes Exploitation: 2032 - - - - - - Magallanes Magallanes Exploitation: 2043 Exploitation: 2044 Exploration: 2019 20 Magallanes Exploitation: 2044 Exploration: 2020 - Magallanes Exploitation: 2045 Exploration: 2019 Campanario 192.2 50 %(5) ENAP GeoPark Flamenco 105.9 50 %(5) ENAP GeoPark 0.1 106 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 Fell Block In 2006, we became the operator and 100% interest owner of the Fell Block. such block. LGI has a 20% direct equity interest in our Chilean operations When we first acquired an interest in the Fell Block in 2002, it had no material through GeoPark Chile. See “-Significant agreements-Agreements with LGI-LGI oil and gas production. Since then, we have completed more than 1,100 sq. km Chile Shareholders’ Agreements.” (2) Partners with working interests. (3) As of December 31, 2015. (4) In April 2013, we voluntarily relinquished to the Chilean government all of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our of 3D seismic surveys and drilled 113 exploration and development wells. In the year ended December 31, 2015, we produced an average of approximately 3,708 boepd, in the Fell Block, consisting of 51% oil. The Fell Block has an area of approximately 368,000 gross acres (1,488 sq. km) partners under the joint operating agreement governing the Otway Block and its center is located approximately 140 km northeast of the city of Punta decided to withdraw from such joint operating agreement, and applied for an Arenas. It is bordered on the north by the international border between assignment of rights permit on August 5, 2013. In September 2014, the Chilean Argentina and Chile and on the south by the Magellan Strait. Ministry of Energy approved that we will be the sole participant with a working interest of 100%. See “-Otway and Tranquilo Blocks.” (5) 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 a The first exploration efforts began on the Fell Block in the 1950s. Through 2005, ENAP carried out seismic surveys and drilled numerous wells in the block. From 2006 through August 2011, we invested approximately US$210 million in exploring total effective equity interest of 31.2% in our Tierra del Fuego operations. See and developing the Fell Block, which allowed us to transition approximately 84% of “-Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)” and the Fell Block’s area from an exploration phase into an exploitation phase, which “-Significant agreements-Agreements with LGI-LGI Chile Shareholders’ we expect will last through 2032. During the exploration phase, we exceeded the Agreements.” (6) At December 31, 2015, the Consortium members and interest were: GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. During 2014 minimum work and investment commitment required under the Fell Block CEOP by more than 75 times, and as of December 31, 2015, had invested more than US$500 million in the Fell Block. There are no minimum work and investment Methanex and Wintershall announced their decision to exit the Consortium, commitments under the Fell Block CEOP associated with the exploitation phase. which was approved by the Chilean Ministry of Energy but not formalized yet. The new ownership is expected to be GeoPark 50% and Pluspetrol 50%. The Fell Block is located in the north-eastern part of the Magallanes Basin. The principal producing reservoir is composed of sandstones in the Springhill formation, at depths of 2,200 to 3,500 meters. Additional reservoirs have been discovered and put into production in the Fell Block-namely, Tobífera formation volcanoclastic rocks at depths of 2,900 to 3,600 meters, and Upper Tertiary and Upper Cretaceous sandstones, at depths of 700 to 2,000 meters. GeoPark 79 Our geosciences identified and developed an attractive inventory of prospects In the specific area of our Tierra del Fuego Blocks, the first wells were drilled in and drilling opportunities for both exploration and development in the Fell 1951, resulting in the discovery of the Sombrero oil and gas field. At the end of Block. Previous oil discoveries in the Konawentru, Yagán, Yagán Norte, Copihue the 1950s and in the early 1960s, new fields were discovered to the east (the and Guanaco fields have opened up new oil and gas potential in the Fell Block. Catalina and Cuarto Chorrillo fields) and, following the gathering of seismic An important discovery during 2011 was the Konawentru 1 well, which we reflection data acquisition, additional new fields were discovered and existing initially tested to have in excess of 2,000 bopd from the Tobífera formation, fields were further developed. During the past decade, geological studies in and which has opened up additional potentially attractive opportunities the Magallanes Basin have focused on stratigraphic analysis, based on 3D and (workovers, well-deepening’s and new exploration and development wells) in 2D seismic information, the definition and distribution of facies of the deltaic the Tobífera formation throughout the Fell Block. and/or turbidite depositional systems of the Late Cretaceous-Tertiary period and the evolution of the oil system in terms of generation/timing/expulsion As a result of this, during 2012 to 2014, we focused our exploration and and trapping. development plan in the Tobífera formation by drilling wells in Konawentru, Yagán and Yagán Norte fields, as well as deepening existing wells in Ovejero Our Tierra del Fuego Blocks are located in the south-eastern margin of the and Molino. Exploration efforts in 2014 resulted in the discoveries of the Ache Magallanes Basin. The principal producing reservoir is composed of sandstones gas field and the Loij oil field. in the Springhill formation at depths of 1,800 to 2,300 meters. Additional reservoirs have been discovered and put into production in the Tierra del During 2015, although there were no wells drilled, we put into production a Fuego Blocks namely Tobífera formation volcanoclastic rocks at depths of 2,000 new gas field, Ache, that was discovered in 2014. After the construction and to 2,500 meters, and Upper Terciary and Upper Cretaceous sandstones, at start-up of a gas treatment facility, the field has been producing at a rate of depths of 500 to 1,400 meters. approximately 6.7 mmcfpd. We also continue to evaluate the Estratos con Favrella shale reservoir, which partnership with ENAP in the Isla Norte Block, which covers approximately we believe represents a high-potential, unconventional resource play for shale 130,200 gross acres (527 sq. km). As of March 2016 we had completed 100% of oil and gas, as a broad area of the Fell Block (1,000 sq. km) appears to be in the the committed 350 sq. km of 3D seismic surveys. We have also committed to Isla Norte Block. We are the operator of, and have a 60% working interest in oil window for this play. drilling three wells during the first exploration period under the CEOP governing the Isla Norte Block. Pantano Oeste 1 well marks the first oil discovery on the Isla Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks) Norte Block. As of the date of this annual report, outstanding investment In the first and second quarters of 2012, we entered into three CEOPs with ENAP commitments related to this Block corresponds to 2 exploratory wells until May and Chile granting us working interests in the Isla Norte, Campanario and 7, 2017 for approximately US$6.5 million. In the year ended December 31, 2015, Flamenco Blocks, located in the center-north of the Tierra del Fuego province of we produced an average of approximately 20 boepd, in the Isla Norte Block. Chile. We are the operator of all three of these blocks, with working interests of 60%, 50% and 50%, respectively. We believe that these three blocks, which collectively Campanario Block. We are the operator of, and have a 50% working interest in, the cover 463,700 gross acres (1,877 sq. km) and are geologically contiguous to the Fell Campanario Block, in partnership with ENAP. The block covers approximately 192,200 Block, represent strategic acreage with resource potential. We have committed to gross acres (778 sq. km). As of March 31, 2016, we had completed 100% of the paying 100% of the required minimum investment under the CEOPs covering committed 578 sq. km of 3D seismic surveys. We have also committed to drilling these blocks, in an aggregate amount of US$101.4 million through the end of the eight wells during the first exploration period under the CEOP governing the first exploratory periods for these blocks, which occurred in November 2015 for the Campanario Block. As of December 31, 2015 we drilled 5 exploratory wells, including Flamenco Block and we expect will occur by May 2017 for the Isla Norte Block and the Primavera Sur 1 well that marks the first discovery of an oil field on the by July 2017 for the Campanario Block, which includes our covering of ENAP’s Campanario Block in addition to one development well. As of the date of this annual investment commitment corresponding to its working interest in the blocks. report, outstanding investment commitments related to this block correspond to 3 exploratory wells until July 11, 2017 for approximately US$11.9 million. In the first quarter of 2012, we began 3D seismic operations in the Flamenco Block. As of March 2016, 16 wells have been drilled (for a total investment commitment Flamenco Block. We are the operator of, and have a 50% working interest in, the of 21 wells) and 1,500 sq. km of 3D seismic have been carried out over the three Flamenco Block, in partnership with ENAP. The block covers approximately blocks; which represent the total 3D seismic program commitment. 141,300 gross acres (582 sq. km). In June 2013, we discovered a new oil and gas field in the block following the successful testing of the Chercán 1 well, the first Exploration in the Tierra del Fuego province in the Magallanes Basin dates well drilled by us in Tierra del Fuego. As of March 31, 2016, we had completed back to the 1940s, when the first surface exploration focused on obtaining 100% of the committed 570 sq. km of 3D seismic surveys. We have also stratigraphic and structural information. Structural traps with transgressive committed to drilling ten wells during the first exploration period under the sandstone reservoirs (Springhill formation) were outlined with refraction CEOP governing the Flamenco Block. As of the date of this annual report, there seismic lines and, in 1945, oil was discovered. are no outstanding investment commitments related to this block. In the year 80 GeoPark 20F ended December 31, 2015, we produced an average of approximately 106 As of December 31, 2015, we had completed our minimum work commitments boepd in the Flamenco Block. for the Otway and Tranquilo Blocks, with a total investment of approximately US$24.0 million for the first exploratory period. The Otway Block’s seismic The first exploration period of the Flamenco Block ended in November 2015, commitment program was completed in 2011 and included 270 sq. km of 3D and we and ENAP notified the Ministry of Energy of our decision to continue seismic and 127 km of 2D seismic survey work. with the second exploration period, which will last for 2 years. As of the date of this annual report, outstanding investment commitments related to this block Operations in Brazil correspond to 1 exploratory well until November 7, 2017 for approximately Our Brazilian assets currently give us access to 304,000 of gross exploratory US$2.1 million, to be assumed 100% by us. and productive acres across 13 blocks (12 exploratory blocks and the BCAM-40 Concession, which is in production phase) in an attractive oil and Otway and Tranquilo Blocks gas geography. We are the operator of the Otway and Tranquilo Blocks. Highlights of the year ended December 31, 2015 related to our operations in In the Otway Block, as of December 31, 2013, we had a 25% working interest Brazil included: and our partners were Pluspetrol (25%), Wintershall (25%), IFC (12.5%) and • Compression plant completed in BCAM-40 Concession (Manati) to stabilize Methanex (12.5%). Our partners withdrew from the joint operating agreement production and develop remaining gas field proved reserves (100% classified governing the Otway Block in May 2013, and applied to the Chilean Ministry of proved developed) Energy to assign their rights to us in the Otway Block CEOP in August 2013. In • Capital expenditures reduced by 51%, to US$5.6 million in 2015, from September 2014, the Chilean Ministry of Energy approved that we will be the US$11.4 in 2014 sole participant with a working interest of 100%. In 2012, we drilled two wells in • Four new attractive exploratory blocks awarded in the Reconcavo and the Otway Block, both of which were subsequently plugged and abandoned. Potiguar basins (Round 13). On April 10, 2013, we voluntarily and formally announced to the Chilean The map below shows the location of our concessions in Brazil in which we Ministry of Energy our decision not to proceed with the second exploratory have a current or future working interest, including the BCAM-40 Concession period and to terminate the exploratory phase under the Otway Block CEOP, and the concessions from bidding rounds 11, 12 and 13. such that we relinquished all areas of the Otway Block, except for two areas totaling 49,421 gross acres in which we declared the discovery of hydrocarbons, in the Cabo Negro and Tatiana prospect areas. In the Tranquilo Block, as of December 31, 2015, we had a 29% working interest, where our partners were Pluspetrol (29%), Wintershall (25%) and Methanex (17%). During 2014 Methanex and Wintershall announced their decision to exit the Consortium, which was approved by the Ministry of Energy but has not yet been formalized. The new ownership is GeoPark 50% and Pluspetrol 50%. 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. The Marcou Sur well is under evaluation and we discovered gas in the El Salto formation of the Palos Quemado well. At the Palos Quemados well, we completed a 22-week commercial feasibility test aimed at defining its productive potential. As the test was not conclusive, we were granted permission by the Chilean Ministry of Energy to extend the testing period for an additional six months. Upon such testing period, we kept 4 provisional protection areas, which enabled continued analysis of the area prior the declaration of its commercial viability for a period of 5 years. On January 17, 2013, we formally announced to the Chilean Ministry of Energy our decision not to proceed with the second exploratory period and to terminate the exploratory phase of the Tranquilo Block CEOP. Subsequently, we relinquished all areas of the Tranquilo Block, except for a remaining area of 92,417 gross acres, for the exploitation of the Renoval, POT - T 882 B R A Z I L POT - T 619 POT - T 747 POT - T 663 POT - T 664 PN - T 597(1) POT - T 665 POT - T 620 9 POT - T 85 POT - T 94 POT - T 93 POT - T 128 SEAL - T 268 BCAM - 40 (Manati) P A R A G U A Y A R G E N T I N A (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 Marcou Sur, Estancia Maria Antonieta and Palos Quemados Fields, which we have factors-Risks relating to our business-The PN-T-597 Concession Agreement in identified as the areas with the most potential for prospects in the block. Brazil may not close.” GeoPark 81 The following table sets forth information as of December 31, 2015 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 and 13. Concession REC-T 94 REC-T 85 POT-T 664 POT-T 665 POT-T 619 POT-T 620 POT-T 663 PN-T-597(4) SEAL-T-268 REC-T-93 REC-T-128 POT-T-747 POT-T-882 Gross acres (thousand acres) Working interest(1) Net proved reserves Production Partners Operator (mmboe) (boepd) Basin Concession expiration year Exploration: 2018 7.7 7.7 7.9 7.9 7.9 7.9 7.9 188.7 7.8 7.8 7.6 6.9 7.9 100% 100% 100% 100% 100% 100% 100% 100%(5) 100% 100%(6) - - - - - - - -(5) - - GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark 70% Geosol GeoPark 100%(6) 100%(6) - - GeoPark GeoPark - - - - - - - - - - - - - - - - - - - - - - - - - - Recôncavo Exploitation: 2045 Exploration: 2018 Recôncavo Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Potiguar Parnaíba Sergipe Alagoas Exploration: 2018 Exploitation: 2045 -(4) Exploration: 2019 Exploitation: 2046 Exploration: 2020 Recôncavo Exploitation: 2047 Exploration: 2020 Recôncavo Exploitation: 2047 Exploration: 2020 Potiguar Exploitation: 2047 Exploration: 2020 Potiguar Exploitation: 2047 BCAM-40 22.8 10% Petrobras; QGEP; Brasoil Petrobras 6.1 3,342 Camamu- Almada Exploitation: 2029(2) - 2034(3) (1) Working interest corresponds to the working interests held by our respective subsidiaries, net of any working interests held by other parties in (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 this such concession, and including the working interest we expect to hold in annual report, confirmation remains subject to final signing and local PN-T-597 which as of the date of this report is pending approval. See “Item 3. authority approval. See “Item 3. Key Information-D. Risk factors-Risks relating to Key Information-D. Risk factors-Risks relating 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. our business-The PN-T-597 Concession Agreement in Brazil may not close.” (5) See “Item 3.Key Information-D. Risk Factors-Risks relating to our business-The PN-T-597 Concession Agreement in Brazil may not close.” (6) A 30% working interest of proposed partners is subject to ANP approval. 82 GeoPark 20F BCAM-40 Concession The exploratory phase for these concessions is divided into two exploratory As a result of the Rio das Contas acquisition, we have a 10% working interest in periods, the first of which lasts for three years and the second of which is the BCAM-40 Concession, which includes interests in the Manati Field and the non-obligatory and can last for up to two years. Camarão Norte Field, and which is located in the Camamu-Almada Basin. Petrobras is the operator, and has a 35% working interest in, the BCAM-40 During bidding, a work program offer is made in the form of work units and the Concession, which covers approximately 22,784 gross acres (92.2 sq. km). In ANP asks for a guarantee of a monetary amount proportional to the offered addition to us, Petrobras’ partners in the Block are Brasoil and QGEP, with 10% units. However, depending on the work performed by the operator, the actual and 45% working interests, respectively. Petrobras operates the BCAM-40 work program investment might have a different value to the guaranteed value. Concession pursuant to a concession agreement with the ANP, executed on August 6, 1998. See “-Significant agreements-Brazil-Overview of concession REC-T 94 and REC-T 85 Concessions agreements-BCAM-40 Concession Agreement.” In September 2009, Petrobras The Recôncavo Basin covers an area of approximately 2.7 million gross acres announced the relinquishment of BCAM-40’s exploration area within the (11,000 sq. km). According to the ANP, as of December 31, 2015, 76 fields were concession to the ANP, except for the Manati Field and the Camarão Norte Field. producing in the Reconcavo Basin. The Manati Field is located 65 km south of Salvador, offshore at a 35 meter In the REC-T 94 and REC-T 85 Concessions we committed R$19.3 million water depth. The field was discovered in October 2000, and, in 2002, Petrobras (approximately US$4.9 million, at the December 31, 2015 exchange rate of declared the field commercially viable. Production began in January 2007. As R$3.9046 to US$1.00) during the first exploratory period consisting of drilling of December 31, 2015, 11 wells had been drilled in the Manati Field, six of two exploratory wells and 31 sq. km of 3D seismic surveys in the REC-T 94 which are productive and connected to a fixed production platform installed Concession and 30 sq. km of 2D seismic surveys in REC-T 85 Concession. 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 During the year 2014 we executed a 3D seismic survey acquisition covering Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to both Reconcavo blocks. Seismic data processing was concluded in 2015. After Petrobras up to a maximum volume as determined in the existing Petrobras ANP approval, this seismic acquisition will fulfill the work program Gas Sales Agreement (as defined below). In July 2015, we signed an commitment for the Block REC-T 85 and part of the REC-T 94. Seismic data amendment to the existing Gas Sales Agreement with Petrobras that covers interpretation is currently ongoing. 100% of the remaining gas reserves of the Manati Field. Our acquisition of Rio das Contas also provides us with a long-term off-take The Potiguar Basin encompasses an area of approximately 23.2 million gross contract with Petrobras that covers 100% of net proved gas reserves in the acres (94,000 sq. km), of which 7.7 million gross acres (31,300 sq. km) are Manati Field, a valuable relationship with Petrobras and an established local located onshore. The onshore part of the basin is considered mature in terms platform and presence, with a seasoned and experienced geoscience and of hydrocarbon exploration. As of December 31, 2015, according to the ANP, administrative team to manage the assets and to seek new growth opportunities. there were 83 fields in production including the onshore and offshore POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions portions of the Potiguar Basin. Also in 2015, in order to improve the field gas recovery and production, Manatì’s consortium built an onshore compression plant that started operating in August In the POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions 2015. The compression plant involved capital expenditures of approximately we committed investments of R$11.3 million (approximately US$2.9 million at US$3.7 million at our working interest and allowed us to classify all existing the December 31st, 2015 exchange rate of R$3.9046 to US$1.00) during the first proved undeveloped reserves as proved developed as of December 31, 2015. exploratory period, equivalent to 222 km of 2D seismic work. Some environmental licenses related to operation of the Manati Field During the year 2014 we executed a 2D seismic survey acquisition. Seismic data production system and natural gas pipeline are expired. However, the operator processing was concluded in 2015. After ANP approval, this seismic acquisition submitted, timely, the request for renewal of those licenses and as such this will fulfill the work program commitments for the blocks. Seismic interpretation operation is not in default as long as the regulator does not state its final is currently ongoing. position on the renewal. The Camarão Norte Field is in the development phase and is not yet subject to the environmental licensing requirement. Round 12 Concessions Round 11 Concessions During ANP’s 11th bidding round, held in May 14th, 2013, we were awarded 7 exploratory blocks, of which 2 were in the Reconcavo basin in the state of Bahia On November 28, 2013, in the 12th oil and gas bidding round, the ANP awarded us two new concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of Maranhăo and the SEAL-T-268 Concession in the Sergipe Alagoas Basin) in the State of Alagoas. During bidding, a work program offer is made in and 5 were in the Potiguar basin in the state of Rio Grande do Norte. the form of work units and the ANP asks for a guarantee of a monetary amount GeoPark 83 proportional to the offered units. However, depending on the work performed Total commitment to the ANP was of R$8.5 million (approximately US$2.17 by the operator, the actual work program investment might have a different million, at the December 31, 2015 exchange rate of R$3.9046 to US$1.00) during value to the guaranteed value. the first exploratory period and is equivalent to acquiring 70 km of 2D seismic, For more information, see “Item 3. Key information-D. Risk factors-Risks relating to our business-The PN-T-597 Concession Agreement in Brazil may not close.” REC-T-128 and REC-T-93 and drilling one well. PN-T-597 Concession 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 The Parnaiba Basin, which covers an area of approximately 148 million gross with Geosol with a 70 % working interest for us and 30% working interest for acres (600,000 sq. km), is a basin with large underexplored areas. As of Geosol. December 31, 2015, the basin had two fields in production in the basin. In the PN-T-597 Concession we committed R$7.7 million (approximately US$2 at the December 31st, 2015 exchange rate of R$3.9046 to US$1.00) during the million, at the December 31st, 2015 exchange rate of R$3.9046 to US$1.00) for first exploratory period and consists of acquiring 9 km3 of 3D seismic, drilling the first exploratory period, equivalent to 180 km of 2D seismic. one well and performing geochemical analysis at two levels. The total commitment to the ANP was R$7.9 million (approximately 2.0 million The exploratory phase for this concession is divided into two exploratory Operations in Peru periods. Given that Parnaiba Basin is considered as a “new frontier” area by the In October 2014, we entered into an agreement to expand our footprint into ANP, the first exploratory period lasts four years, and the second exploratory Peru (our fifth country platform in Latin America) through the pending period, which is optional, can last for up to two years. acquisition of Morona Block in a joint venture with Petroperu. See “Item 3. Key Information-D. Risk factors-Risks relating to our business-The The Morona Block has D&M certified net proved reserves of 18.8 mmboe as of PN-T-597 may not close” and “-D. Risk factors-Risks relating to the countries in December 31, 2015, composed of 100% oil. which we operate-Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we The map below shows the location of the Morona Block in Peru in which we may operate in the future” for more information. expect to have a working interest pending completion of our acquisition. SEAL-T-268 Concession The Sergipe-Alagoas Basin encompasses an area of approximately 10.9 million gross acres (44,400 sq. km), of which 3.1 million gross acres (12600 sq. km) are situated onshore. As of December 31, 2015, according to the ANP, there were 30 fields in production on the basin. In the SEAL-T-268 Concession we committed R$1.6 million (approximately US$0.4 million, at the December 31st, 2015 exchange rate of R$3.9046 to US$1.00) for the first exploratory period, equivalent to 40 km of 2D seismic. The exploratory phase for this concession is divided into two exploratory periods, the first lasting three years, and the second, which is optional, can last for up to two years. Round 13 Concessions During ANP’s round 13 bidding held on October 7, 2015, we were awarded four exploratory concessions, of which two were in the Potiguar Basin in the state of Rio Grande do Norte and two were in the Reconcavo Basin in the state of Bahia. The exploratory phase for these concessions is divided into two exploratory 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. POT-T-747 and POT-T-882 The POT-T-747 and POT-T-882 blocks are located in the Potiguar Basin and encompass an area of 14,829 acres (60 square km). 84 GeoPark 20F E C U A D O R C O L O M B I A Morona(1) P E R U P A C I F I C O C E A N B R A Z I L B O L I V I A C H I L E (1) Transaction executed with Petroperu on October 1, 2014 with final closing subject to approval by the Peruvian government. The table below summarizes information about the Block in Peru in which we expect to have a working interest pending completion of our acquisition. Block Morona Gross acres (thousand acres) 1,881 Working interest(1) 75% Operator GeoPark Net proved reserves (mmboe)(2) 18.8 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 high impact prospects and plays. This important component of the project will significantly increase our overall inventory of exploration resources. The of our investments in the block through agreed terms in the Petroperu SPA. Morona Block includes geophysical surveys of 2,783 km (2D seismic) and 465 See “Item 4. Information on the Company-B. Business overview-Our sq. km (3D seismic), and an operating field camp and logistics infrastructure. operations-Operations in Peru-Morona Block.” (2) Certified by D&M as of December 31, 2015. (3) The concession year expiration is related to approval of an environmental impact assessment (EIA) study for project development. The concession will The area has undergone oil and gas exploration activities for the past 40 years, and there exist ongoing association agreements and cooperation projects with the local communities. expire twenty (20) years after EIA approval. We expect the EIA to be approved The expected work program and development plan for the Situche Central oil around December 2018. Morona Block field is to be completed in three stages. The goal of the initial stage will be to put the field into production through a long term test to help determine the most effective overall development plan and to begin to generate cash flow. The Morona Block covers an area of approximately 1,881 thousand gross acres This initial stage requires an investment of approximately US$140 million to (7,600 sq. km). More than 1 billion barrels of oil have been produced from the US$160 million and is expected to be completed within 18 to 24 months after surrounding blocks in this basin. If the acquisition is approved by the Peruvian closing. We have committed to carry Petroperu, by paying its portion of the Government, we will have a 75% working interest in the Morona Block. For the required investment in this initial phase. year ended December 31, 2015, net proved reserves at the Morona Block were 18.8 mmboe (composed of 100% oil). The subsequent work program stages, which will be initiated once production has been established, are focused on carrying out the full development of the On October 1, 2014, we entered into an agreement to acquire a 75% working Situche Central field, including transportation infrastructure, and new interest in the Morona Block in Northern Peru. As stated above, this agreement exploration drilling of the block. includes a work program to be executed by us. This program includes 3 phases, and we may decide whether to continue or not at the end of each phase. The exploratory program entails drilling one exploratory well. Exploratory program capital expenditures will be borne exclusively by us. The closing of the acquisition is subject to certain conditions that include obtaining governmental approvals. The current agreement provides until June Initially we will have a 75% working interest. However, according to the terms 30, 2016 to obtain regulatory approvals. If the conditions precedent are not of the agreement, Petroperu will have the right to increase its working interest satisfied by such date, each party will have the right to terminate the contract in the block by up to 50%, subject to the recovery of our investments in the without liability. The parties have repeatedly amended the deadline to obtain block by certain agreed factors. regulatory approvals in the past to provide sufficient time to complete the regulatory approval process. We are currently evaluating a new deadline In Peru, there is a 5-20% sliding scale royalty rate, depending on production extension with Petroperu, but we cannot be sure that the extension will occur levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For or that we will be able to obtain the required regulatory approvals. Presidential production between 5,000 and 100,000 bopd there is a linear sliding scale elections taking place in 2016 in Peru could also affect regulatory approval of between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%. the Morona Block Acquisition. See “Item 3. Key Information-D. Risk Factors- Risks relating to our business- Our pending acquisition of the Morona Block in Peru is subject to regulatory approvals.” The Morona Block contains the Situche Central oil field, which has been delineated by two wells (with short term tests of approximately 2,400 and 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the Situche Central field, the Morona Block has a large exploration potential with several GeoPark 85 Operations in Argentina The map below shows the location of the blocks in Argentina in which we have working interests as of December 31, 2015. B O L I V I A P A R A G U A Y A R G E N T I N A B R A Z I L U R U G U A Y Sierra del Nevado Puelen CV-V(1) C H I L E Del Mosquito (1) Farm-in agreement signed on July 22, 2015 with Wintershall. The table below summarizes information about the blocks in Argentina in which we have working interests as of December 31, 2015. Block Del Mosquito Puelen(3) Sierra del Nevado(3) CN-V Gross acres (thousand acres) 17.3 305.4 1,433.2 117.0 Working interest(1) 100% 18% 18% 50% Operator GeoPark Pluspetrol Pluspetrol GeoPark Net proved reserves (mmboe)(2) - - - - Production (boepd) 7 - - - Basin Austral Neuquén Neuquén Neuquén Expiration concession year Exploitation: 2016 Exploration: 2017 Exploration: 2017 Exploration: 2017 (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, 2015. (3) Blocks awarded in the 2014 Mendoza Bidding Round. 86 GeoPark 20F Del Mosquito Block 180 sq. km and is adjacent to the producing Loma Alta Sur oil field, a region and We are the operator of, and hold 100% working interest in, the Del Mosquito play-type well known to our team. The block includes upside potential in the Block. We established oil production in the block in 2002 by rehabilitating the developing Vaca Muerta unconventional play. abandoned Del Mosquito Field and subsequently discovered the Del Mosquito Norte field. For the year ended December 31, 2015, our average daily Oil and natural gas reserves and production production at the Del Mosquito Block was 7 boepd due to the impact of the Overview temporary shut down of our operations in this block in the first quarter of 2015. We have achieved consistent growth in oil and gas reserves from our 2014 Mendoza Bidding Round investment activities since 2007, when we began production in the Fell Block. As of December 31, 2015, D&M reported that our total net proved reserves in On August 20, 2014, the consortium of Pluspetrol and us was awarded two Colombia, Chile, and Brazil were 48.6 mmboe. Of this total, 30.4 mmboe or 63%, exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 12.0 mmboe, or 25%, and 6.1 mmboe, or 12%, were in Colombia, Chile and 2014 Mendoza Bidding Round in Argentina, carried out by Empresa Mendocina Brazil, respectively, and we had no net proved reserves in Argentina. The D&M de Energía S.A. (“EMESA”). These licenses rebalanced our Argentinean portfolio Reserves Report estimates total net proved reserves for the Morona Block in following the decision to relinquish the non-productive Cerro Doña Juana and Peru to be 18.8 mmboe. Loma Cortaderal Blocks during 2014. The consortium consists of Pluspetrol (operator with a 72% working interest), Brazil and Argentina as of December 31, 2015. The following table summarizes our net proved reserves in Colombia, Chile, EMESA (non-operator with a 10% working interest) and us (non-operator with an 18% working interest). In accordance with the terms of the bidding, all of the expenditures related to EMESA’s working interest will be carried by Pluspetrol and us proportionately to our respective working interests, and will be recovered through EMESA’s participation in future potential production. Puelen Block: the Puelen Block covers an area of approximately 305.4 thousand gross acres, and is located in the Neuquén Basin in southern Argentina. Sierra del Nevado Block: the Sierra del Nevado Block covers an area of approximately 1,433.2 thousand gross acres, and is located in the Neuquén Country Colombia Chile Brazil Argentina Total Oil (mmbbl) 30.4 6.0 0.1 - 36.5 Total net proved reserves (mmboe)(1) 30.4 12.0 6.1 - 48.6 Gas (bcf ) - 36.5 36.2 - 72.7 % Oil 100% 49% 2% - 75% Basin in southern Argentina. (1) We calculate one barrel of oil equivalent as six mcf of natural gas. We have committed to a minimum aggregate investment of US$6.2 million for The following table summarizes the net proved reserves in Peru for the this working interest, which includes the work program commitment on both pending Morona Block Acquisition as of December 31, 2015, according to the blocks during the first three years of the exploratory period. D&M Reserves Report. Country Peru Total Oil (mmbbl) 18.8 18.8 Total net proved reserves (mmboe)(1) 18.8 18.8 Gas (bcf ) - - % Oil 100% 100% According to the Secretariat of Energy (Secretaría de Energía) in Argentina (“Argentine Secretariat of Energy”), for the year ended December 31, 2015, the Neuquén Basin produced approximately 40% of Argentina’s total oil production and approximately 56% of its total gas production. CN-V Block Farm-in Agreement with Wintershall On July 22, 2015, we signed a farm-in agreement with Wintershall for the 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 our commitment until 2017 to drill two exploratory wells, for a total of US$10 million. The CN-V Block covers an area of approximately 117,000 acres and is located in the Neuquén Basin in southern Argentina. The block has 3D seismic coverage of GeoPark 87 Our reserves Table 5 included in Note 37 (unaudited) to our Consolidated Financial The following table sets forth our oil and natural gas net proved reserves as of Statements. December 31, 2015, which is based on the D&M Reserves Report. Internal controls over reserves estimation process Net proved reserves We maintain an internal staff of petroleum engineers and geosciences As of December 31, 2015 professionals who work closely with our independent reserves engineers to Total net proved reserves (mmboe)(1) 8.2 1.3 6.1 ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimation process and who have knowledge of the specific properties under evaluation. Our Director of % Oil Development, Carlos Alberto Murut, is primarily responsible for overseeing the preparation of our reserves estimates and for the internal control over our 100% reserves estimation. He has more than 30 years of industry experience as an 38% E&P geologist, with broad experience in reserves assessment, field 2% development, exploration portfolio generation and management and 15.6 56% acquisition and divestiture opportunities evaluation. See “Item 6. Directors, Senior Management and Employees-A. Directors and senior management.” 22.2 10.7 - 100% 51% In order to ensure the quality and consistency of our reserves estimates and - reserves disclosures, we maintain and comply with a reserves process that satisfies the following key control objectives: Oil Natural (mmbbl) gas (bcf ) 8.2 0.5 0.1 8.8 22.2 5.5 - - 4.9 36.2 41.1 - 31.6 - 27.7 31.6 33.0 84% • estimates are prepared using generally accepted practices and Net proved developed Colombia Chile Brazil Total net proved developed Net proved undeveloped Colombia Chile Brazil Total net proved undeveloped Total net proved (Colombia, Chile, Brazil) 36.5 72.7 48.6 75% methodologies; (1) We calculate one barrel of oil equivalent as six mcf of natural gas. • estimates and changes therein are prepared on a timely basis; • estimates are prepared objectively and free of bias; The following table sets forth the oil and natural gas net proved reserves as of • estimates and related disclosures are prepared in accordance with December 31, 2015, for the Morona Block in Peru which is based on the D&M regulatory requirements. • estimates and changes therein are properly supported and approved; and Reserves Report. Oil Natural (mmbbl) gas (bcf ) Net proved developed Peru Total net proved developed Net proved undeveloped Peru Total net proved undeveloped Total net proved (Peru) 6.5 6.5 12.2 12.2 18.8 - - - - - Throughout each fiscal year, our technical team meets with Independent Net proved reserves Qualified Reserves Engineers, who are provided with full access to complete As of December 31, 2015 and accurate information pertaining to the properties to be evaluated and all Total net proved reserves (mmboe)(1) 6.5 6.5 applicable personnel. This independent assessment of the internally- generated reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free of preparer and % Oil management bias. 100% Recognizing that reserves estimates are based on interpretations and 100% judgments, differences between the proved reserves estimates prepared by us and those prepared by an Independent Qualified Reserves Engineer of 10% or 12.2 100% less, in aggregate, are considered to be within the range of reasonable differences. Differences greater than 10% must be resolved in the technical 12.2 18.8 100% meetings. Once differences are resolved, the independent Qualified Reserves 100% Engineer sends a preliminary copy of the reserves report to be reviewed by the Technical Committee and Directors of each Business Unit. A final copy of (1) We calculate one barrel of oil equivalent as six mcf of natural gas. the Reserves Report is sent by the Independent Qualified Reserve Engineer to For further information relating to the reconciliation of our net proved See “Item 6. Directors, Senior Management and Employees-C. Board Practices- reserves for the years ended December 31, 2015, 2014 and 2013, please see Committees of our board of directors.” be approved and signed by the Technical Committee and our CEO and CFO. 88 GeoPark 20F Independent reserves engineers However, uncertainties are inherent in estimating quantities of reserves, Reserves estimates as of December 31, 2015 for Colombia, Chile, Brazil and including many factors beyond our and our independent reserves engineers’ Peru included elsewhere in this annual report are based on the D&M Reserves control. Reserves engineering is a subjective process of estimating subsurface Report, dated April 15, 2016 and effective as of December 31, 2015. The D&M accumulations of oil and natural gas that cannot be measured in an exact Reserves Report, a copy of which has been filed as an exhibit to this annual manner, and the accuracy of any reserves estimate is a function of the quality report, was prepared in accordance with SEC rules, regulations, definitions and of available data and its interpretation. As a result, estimates by different guidelines at our request in order to estimate reserves and for the areas and engineers often vary, sometimes significantly. In addition, physical factors such period indicated therein. as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or development D&M, a Delaware corporation with offices in Dallas, Houston, Calgary, Moscow and production expenses, and regulatory factors, such as royalties, and Algiers, has been providing consulting services to the oil and gas industry development and environmental permitting and concession terms, may for more than 75 years. The firm has more than 150 professionals, including require revision of such estimates. Our operations may also be affected by engineers, geologists, geophysicists, petrophysicists and economists that are unanticipated changes in regulations concerning the oil and gas industry in engaged in the appraisal of oil and gas properties, the evaluation of the countries in which we operate, which may impact our ability to recover the hydrocarbon and other mineral prospects, basin evaluations, comprehensive estimated reserves. Accordingly, oil and natural gas quantities ultimately field studies and equity studies related to the domestic and international recovered will vary from reserves estimates. energy industry. D&M restricts its activities exclusively to consultation and does not accept contingency fees, nor does it own operating interests in any Technology used in reserves estimation oil, gas or mineral properties, or securities or notes of its clients. The firm According to SEC guidelines, proved reserves are those quantities of oil and subscribes to a code of professional conduct, and its employees actively gas which, by analysis of geoscience and engineering data, can be estimated support their related technical and professional societies. The firm is a Texas with “reasonable certainty” to be economically producible-from a given date Registered Engineering Firm. forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which The D&M Reserves Report covered 100% of our total reserves. In connection contracts providing the right to operate expire, unless evidence indicates that with the preparation of the D&M Reserves Report, D&M prepared its own renewal is reasonably certain, regardless of whether deterministic or estimates of our proved reserves. In the process of the reserves evaluation, probabilistic methods are used for the estimation. D&M did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil The project to extract the hydrocarbons must have commenced or the and gas production, well test data, historical costs of operation and operator must be reasonably certain that it will commence the project within development, product prices, or any agreements relating to current and future a reasonable time. The term “reasonable certainty” implies a high degree of operations of the fields and sales of production. However, if in the course of confidence that the quantities of oil and/or natural gas actually recovered will the examination something came to the attention of D&M that brought into equal or exceed the estimate. Reasonable certainty can be established using question the validity or sufficiency of any such information or data, D&M did techniques that have been proved effective by actual production from not rely on such information or data until it had satisfactorily resolved its projects in the same reservoir or an analogous reservoir or by other evidence questions relating thereto or had independently verified such information or using reliable technology that establishes reasonable certainty. Reliable data. D&M independently prepared reserves estimates to conform to the technology is a grouping of one or more technologies (including guidelines of the SEC, including the criteria of “reasonable certainty,” as it computational methods) that have been field tested and have been pertains to expectations about the recoverability of reserves in future years, demonstrated to provide reasonably certain results with consistency and under existing economic and operating conditions, consistent with the repeatability in the formation being evaluated or in an analogous formation. definition in Rule 4-10(a)(2) of Regulation S-X. D&M issued the D&M Reserves Report based upon its evaluation. D&M’s primary economic assumptions in There are various generally accepted methodologies for estimating reserves estimates included oil and gas sales prices determined according to SEC including volumetrics, decline analysis, material balance, simulation models guidelines, future expenditures and other economic assumptions (including and analogies. Estimates may be prepared using either deterministic (single interests, royalties and taxes) as provided by us. The assumptions, data, estimate) or probabilistic (range of possible outcomes and probability of methods and procedures used, including the percentage of our total reserves occurrence) methods. The particular method chosen should be based on the reviewed in connection with the preparation of the D&M Reserves Report evaluator’s professional judgment as being the most appropriate, given the were appropriate for the purpose served by such report, and D&M used all geological nature of the property, the extent of its operating history and the methods and procedures as it considered necessary under the circumstances quality of available information. It may be appropriate to employ several to prepare such reports. methods in reaching an estimate for the property. GeoPark 89 Estimates must be prepared using all available information (open and cased Of our 33.0 mmboe of net proved undeveloped reserves, 22.2 mmboe (67%) hole logs, core analyses, geologic maps, seismic interpretation, production/ and 10.7 mmboe (33%) were located in Colombia and Chile, respectively. injection data and pressure test analysis). Supporting data, such as working During 2015, we incurred approximately US$9 million in capital expenditures interest, royalties and operating costs, must be maintained and updated when to convert such proved undeveloped reserves to proved developed reserves, such information changes materially. of which approximately US$5 million, and US$4 million were made in Colombia and Brazil respectively. No net proved undeveloped reserves were Proved undeveloped reserves located in Argentina and Brazil as of December 31, 2015. As of December 31, 2015, excluding reserves from the pending acquisition of the Morona Block, we had 33.0 mmboe in proved undeveloped reserves, an The following table shows the evolution of total net proved undeveloped increase of 3.4 mmboe, or 11%, over our December 31, 2014 proved (“PUD”) reserves in the year ended December 31, 2015. undeveloped reserves of 29.6 mmboe. The increase in proved undeveloped oil reserves is mainly due to net additions in Colombia related to the new oil field discoveries in 2015, including the Jacana Field in Llanos 34 Block amounting to (All amounts shown in mmboe) 9.3 mmboe. This was partially offset by proved undeveloped reserves being Plus: Extensions, discoveries converted to proved reserves in Colombia for approximately 5.7 mmboe and and acquisitions: in Brazil for approximately 3.3 mmboe due to the startup of the compression -Colombia plant in the BCAM 40 Concession (Manati), as explained in the table below. -Chile -Brazil 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 Total Net Proved Undeveloped Reserves at December 31, 2015(*) Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2014(*) 29.6 9.3 1.6 - (5.7) - (3.3) 1.5 - - 33.0 (*) Includes proved undeveloped reserves in Colombia, Chile and Brazil and excludes proved undeveloped reserves in Peru as the Morona Block acquisition is not yet closed . As of December 31, 2015, the Morona Block in Peru had 12.2 mmboe in proved undeveloped reserves. 90 GeoPark 20F 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, 2015, 2014 and 2013. 2015 Total 2014 Total Average daily production(1) As of December 31, 2013 Total Chile Colombia Brazil Argentina GeoPark(3) Chile Colombia Brazil Argentina GeoPark Chile Colombia Brazil Argentina GeoPark Oil production Average crude oil production (bopd) 1,938 13,183 48 7 15,176 3,690 10,748 42 61 14,541 4,581 6,482 Average sales price of crude oil (US$/bbl)(3) Natural gas Average natural 42.2 30.4 53.1 76.5 32.0 89.4 73.0 102.4 75.4 77.5 84.3 80.3 gas production (mcfpd) 11,380 - 19,672 - 31,142 14,484 354 15,753 86 30,677 14,283 52 Oil production 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) 4.5 - 4.7 - 4.6 6.2 - 6.5 1.1 6.4 5.0 4.18 21.0 1.5 8.8 1.8 22.5 10.6 4.4 2.6 7.1 - 10.5 16.7 18.4 5.8 11.3 16.2 12.2 26.5 - - 1.9 3.3 3.3 3.1 8.8 3.3 2.9 4.1 12.4 20.0 21.7 8.9 20.1 19.5 15.1 30.6 - - - - - - - 50 11,113 70.3 82.0 84 14,419 1.1 5.0 4.0 19.0 8.3 3.5 12.3 22.5 (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. GeoPark 91 Exploratory wells(1) As of December 31, Chile Colombia Argentina 7.0 4.8 3.0 1.5 10.0 6.3 9.0 6.0 1.0 1.0 10.0 7.0 - - - - - - 2013 Brazil - - - - - - Development wells As of December 31, Chile Colombia Argentina 6.0 6.0 1.0 1.0 7.0 7.0 5.0 2.8 - - 5.0 2.8 - - - - - - 2013 Brazil - - - - - - 2014 Brazil - - - - - - 2014 Brazil - - - - - - Drilling activities Drilling activities The following table sets forth the exploratory wells we drilled as operators in The following table sets forth the exploratory wells we drilled as operators in Colombia, Chile, Brazil and Argentina during the years ended December 31, Colombia, Chile, Brazil and Argentina during the years ended December 31, 2015, 2014 and 2013. 2015, 2014 and 2013. Productive(2) Gross Net Dry(3) Gross Net Total Gross Net Chile Colombia Argentina - - - - - - 3.0 1.4 1.0 0.5 4.0 1.9 - - - - - - 2015 Brazil - - - - - - Chile Colombia Argentina 11.0 7.1 5.0 3.0 16.0 10.1 4.0 1.8 - - - - - - - - - - The following table sets forth the development wells we drilled in Colombia, Chile, Brazil and Argentina during the years ended December 31, 2015, 2014 and 2013. Productive(2) Gross Net Dry(3) Gross Net Total Gross Net Chile Colombia Argentina - - - - - - 2.0 0.9 - - 2.0 0.9 - - - - - - 2015 Brazil - - - - - - Chile Colombia Argentina 16.0 15.0 - - 16.0 15.0 5.0 2.3 2.0 0.9 7.0 3.2 - - - - - - (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. For the year ended December 31, 2015, there were no exploratory wells or development wells drilled in our pending Morona Block acquisition, which is subject to approval by the Peruvian government. 92 GeoPark 20F Developed and undeveloped acreage Productive wells The following table sets forth certain information regarding our total gross The following table sets forth our total gross and net productive wells as of and net developed and undeveloped acreage in Colombia, Chile, Argentina March 31, 2016. Productive wells consist of producing wells and wells capable and Brazil as of December 31, 2015. of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production Colombia Chile Brazil Acreage(1) Argentina facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests (in thousands of acres) owned in gross wells. Total developed acreage Gross Net Total undeveloped acreage Gross Net Total developed and undeveloped acreage Gross Net 6.8 4.4 5.7 2.8 12.5 7.2 4.8 4.6 4.7 4.6 9.5 9.2 4.1 0.4 - - 4.1 0.4 - - - - - - (1) Defined as acreage assignable to productive wells. Net acreage based on our working interest. Oil wells Gross Net Gas wells Gross Net Colombia(2) Chile(2) Productive wells(1) Brazil Argentina 54.0 31.0 - - 60.0 52.0 26.0 24.5 - - 6.0 0.6 5.0 5.0 - - (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 an exploratory, development, or extension well that is not a dry well. (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 For the year ended December 31, 2015, total developed acreage in Peru was their acquisition by us. 1.1 thousand acres (gross) and 0.8 thousand acres (net). Total undeveloped acreage was 2.1 thousand acres (gross) and 1.6 thousand acres (net). Total For the year ended December 31, 2015, there were no productive oil and gas developed and undeveloped acreage was 3.2 thousand acres (gross) and 2.4 wells in our pending Morona Block acquisition. thousand acres (net). GeoPark 93 Present activities accounting for 39.1%, Trafigura 7.9% and Petrominerales 5.8% of our In the first quarter of 2016 we drilled a development well, Pampa consolidated revenues for the same period. Larga-16, in Chile in the Fell Block. The well was drilled at a total depth of 9,745 feet and was tested in the Tobifera formation. Current gas stabilized Under the Trafigura Agreement, we agreed on certain priorities for the production rates are approximately 1.8 mmcfpd. Further production volumes to be transported through the ODL Pipeline. For the first period of the history will be required to determine stabilized flow rates and the extent agreement, beginning on March 1, 2016 to February 2017, Trafigura will receive of the reservoir. 10,000 bopd of our production. Once deliveries of the BP agreement start (expected for July 2016), our delivery priorities will be in the following order: Also, during the first quarter of 2016 we drilled the Ache Este x-1 appraisal well (1) Trafigura’s 5,000 bopd, (2) BP’s 5,000 bopd and (3) all of the production in in Chile in the Fell Block at a total depth of 9,799. The well is currently under excess of the aforementioned to Trafigura. For the second period, from evaluation. February 2017 to April 2018, any additional volumes will be included in a tender offer. Nonperformance of our obligations of delivery in terms, amounts As of 31 December 2015, there were seven exploratory wells that have been and quality of the crude to Trafigura leads us to pay Trafigura’s fare capitalised for a period longer than a year amounting to US$19.3 million and commitments in ODL Pipeline for the transport, dilution and download of three exploratory wells that have been capitalised for a period less than a year crude, and may lead to early termination of the crude sales agreement as well amounting to US$3.6 million. See Note 19 to our Consolidated Financial as the immediate repayment of any amounts outstanding under the Statements. prepayment agreement of up US$100 million, as well as compensation for Marketing and delivery commitments Colombia other damages. On the other hand, the sales contract with BP, which is conditioned on the Our production in Colombia consists primarily of crude oil. Sales for the year “P135 expansion project” that is expected to be complete by July 2016, ended December 31, 2015 were made under short-term agreements, all of requires that we deliver 5.000 bopd of our production for a term of 3 years. which can be renewed by mutual written agreement and allow for early Nonperformance of the required delivery commitments is penalized with a termination by either party with advanced notice and without penalty. 3.50 US$/bbl minimum fare for every barrel not shipped below 5,000 bopd. Evacuation of the oil produced is structured under two types of sales: wellhead If we were to lose any one of our key customers, the loss could temporarily and pipeline. For wellhead sales, delivery point is at the loading station at delay production and sale of our oil in the corresponding block. However, we fields. For pipeline sales, delivery point is at the uploading station that believe we could identify a substitute customer to purchase the impacted discharges to the national pipeline network. In Colombia, pipelines have production volumes. minimum quality conditions that restrict access to the system. Consequently, and because we are mid to heavy oil producers, our entrance to the pipeline Chile network is limited. For the year ended December 31, 2015, we sold Our customer base in Chile is limited in number and primarily consists of ENAP approximately 78% of our production directly at the wellhead and and Methanex. For the year ended December 31, 2015 we sold 100% of our oil approximately 22% to the major oil companies that own capacity in the production in Chile to ENAP and 96% of our gas production to Methanex, with pipelines. Since 2014, access to the pipeline network has improved due to the sales to ENAP and Methanex accounting for 15% and 7%, respectively, of our commencement of the Bicentenario pipeline, which added transportation total revenues in the same period. capacity of 100,000 bopd and opened up additional supply opportunities involving reduced trucking costs. For 2016 we have signed certain agreements Under our oil sales agreement with ENAP, or the ENAP Oil Sales Agreement, with Trafigura and BP that allow direct entrance to the national pipeline ENAP has committed to purchase our oil production in the Fell Block, in the system with an aggregate committed production of 10,000 bopd that are amounts that we produce, and with the limitation being storage capacity at aimed at optimizing costs and maximizing revenues. the Gregorio Terminal. The sales contract with ENAP is commonly revised Oil sales are structured under a price formula based on a market reference costs of ENAP in the Gregorio oil terminal. As of the date of this annual report, Index (Brent or Vasconia) and discounts that consider market fees, quality, we are negotiating a new agreement, effective June 2016. every year to reflect changes in the global oil market and to adjust to logistics handling fees and transportation among other associated costs. For the year ended December 31, 2015, we made 62.1% of our oil sales to one in effect. We deliver the oil we produce in the Fell Block to ENAP at the Gunvor, 12.6% to Trafigura and 9.2% to Petrominerales, with Gunvor Gregorio Terminal, where ENAP assumes responsibility for the oil. ENAP owns Commercial conditions of the amended contract are similar to the previous 94 GeoPark 20F two refineries in Chile in the north central part of the country and must ship Gas Sales Agreement with Petrobras that covers 100% of the remaining gas any oil from the Gregorio Terminal to these refineries unless it is consumed reserves in the Manati Field. locally. We signed the Methanex Gas Supply Agreement in Chile in 2009, which expires in 2017. The Manati Field is developed via a PMNT-1 production platform, which is connected to the Estaçăo Vandemir Ferreira, or EVF, gas treatment plant through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd (9.5 mm3 per day). The existing pipeline connects the field’s platform to On April 1, 2014, we entered into a fifth amendment to the Methanex Gas the EVF gas treatment plant, which is owned by the field’s current Supply Agreement, valid until April 30, 2015, which extended the fourth concession holders. During 2015, in order to improve the field gas recovery amendment terms and conditions to May 18, 2014, and defined new and production, Manatì’s consortium built an onshore compression plant conditions for the winter 2014 period (May 2014 to September 2014) and the that started operating in August 2015, which allowed us to classify all post winter period (October 2014 to April 2015). For the post winter period the existing proved undeveloped reserves as proved developed as of Company committed to deliveries of over 400,000 SCM/d. The fifth December 31, 2015. amendment also waived the DOP and TOP thresholds for both parties, replacing them by reasonable efforts to deliver and take, and giving our gas The BCAM-40 Concession, which includes the Manati Field, also benefits from first priority over any third party supplies to Methanex. the advantages of Petrobras’ size. As the largest onshore and offshore operator in Brazil, Petrobras has the ability to mobilize the resources necessary to On May 1, 2015, we executed a sixth amendment to the Gas Supply support its activities in the concession. Agreement with Methanex, valid until April 30, 2017, which defined new conditions for May 2015 to April 2016 and for May 2016 to April 2017. The sixth The condensate produced in the Manati Field is subject to a condensate amendment also waived the DOP and TOP thresholds for both parties with purchase agreement with Petrobras, pursuant to which Petrobras has reasonable efforts to take and deliver and gave our gas first priority over any committed to purchase all of our condensate production in the Manati Field, third party supplies to Methanex. but only in the amounts that we produce, without any minimum or maximum deliverable commitment from us. The agreement is valid through December We gather the gas we produce in several wells through our own flow lines and 31, 2017 but can be renewed upon an amendment signed by Petrobras and inject it into several gas pipelines owned by ENAP. The transportation of the the seller. gas we sell to Methanex through these pipelines is pursuant to a private contract between Methanex and ENAP. We do not own any principal natural Peru gas pipelines for the transportation of natural gas. In Peru, oil production is generally traded on a free market basis and contracts commercial conditions generally follow international markers, normally WTI If we were to lose any one of our key customers in Chile, the loss could and Brent. As per the Petroperu SPA, Petroperu holds the first option, but not temporarily delay production and sale of our oil and gas in Chile. For a the obligation, to purchase oil produced by us in the Morona Block. If we are discussion of the risks associated with the loss of key customers, See “Item 3. not able to sell our production share at the Block or in Morona Station, we will Key Information-D. Risk factors-Risks relating to our business-We sell almost all have to use the North Peruvian Pipeline. This transportation system is owned of our natural gas in Chile to a single customer, who has in the past and operated by Petroperu, and regulated and supervised by OSINERGMIN, temporarily idled its principal facility” and “-We derive a significant portion of the regulatory body in the hydrocarbons sector. Transportation rates should our revenues from sales to a few key customers.” be negotiated with Petroperu. However, if an agreement cannot be reached between Petroperu and us, transportation rates will be determined by Brazil OSINERGMIN. Our production in Brazil consists of natural gas and condensate oil. Natural gas production is sold through a long-term, extendable agreement with Petrobras, Argentina which provides for the delivery and transportation of the gas produced in the In Argentina, we currently do not have any producing blocks following the Manati Field to the EVF gas treatment plant in the State of Bahia. The contract temporary shut-down of the Del Mosquito Block during the first quarter of is in effect until delivery of the maximum committed volume or June 2030, 2015. whichever occurs first. The contract allows for sales above the maximum committed volume if mutually agreed by both seller and buyer. The price for In the past, we entered into ad hoc contracts with local companies for the the gas is fixed in reais and is adjusted annually in accordance with the transportation of crude from fields in the Del Mosquito Block to the Punta Brazilian inflation index. In July 2015, we signed an amendment to the existing Loyola terminal. GeoPark 95 Significant agreements Colombia E&P Contracts Our E&P Contracts are generally subject to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral termination clauses or termination clauses mandated by Colombian law. We have entered into E&P Contracts granting us the right to explore and Anticipated termination declared by the ANH results in the immediate operate, as well as working interests in, six blocks in Colombia. Additionally, we enforcement of monetary guaranties against us and may result in an action for have applied to the ANH to recognize our economic interest in a seventh damages by the ANH. Pursuant to Colombian law, if certain conditions are met, Colombian block as a working interest. These E&P Contracts are generally the anticipated termination declared by the ANH may also result in a divided into two periods: (1) the exploration period, which may be subdivided restriction on the ability to engage contracts with the Colombian government into various exploration phases and (2) the exploitation period, determined on during a certain period of time. See “Item 3. Key Information-D. Risk factors- a per-area basis and beginning on the date we declare an area to be Risks relating to our business-Our contracts in obtaining rights to explore and commercially viable. Commercial viability is determined upon the completion develop oil and natural gas reserves are subject to contractual expiration of a specified evaluation program or as otherwise agreed by the parties to the dates and operating conditions, and our CEOPs, E&P Contracts and concession relevant E&P Contract. The exploitation period for an area may be extended agreements are subject to early termination in certain circumstances.” until such time as such area is no longer commercially viable and certain other conditions are met. Llanos 34 Block E&P Contract. Pursuant to an E&P Contract between Unión Temporal Llanos 34 (a consortium between Ramshorn and GeoPark Colombia Pursuant to our E&P Contracts, we are required, as are all oil and gas SAS) and the ANH that became effective as of March 13, 2009 (“Llanos 34 Block companies undertaking exploratory and production activities in Colombia, to E&P Contract”), Unión Temporal Llanos 34 was granted the right to explore and pay a royalty to the Colombian government based on our production of operate the Llanos 34 Block, and we and Ramshorn were granted a 40% and a hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, 60% working interest, respectively, in the Llanos 34 Block. We were also as modified by Law 1530 of 2012, the royalties we must pay in connection with granted the right to operate the Llanos 34 Block. On December 16, 2009, we our production of light and medium oil are calculated on a field-by-field basis, entered into a joint operating agreement with Ramshorn and P1 Energy with using the following sliding scale: Production (mbop) Up to 5,000 5,000 to 125,000 125,000 to 400,000 400,000 to 600,000 Greater than 600,000 respect to our operations in the block. As of the date of this annual report, the members of the Union Temporal Llanos 34 are GeoPark Colombia SAS with Production 45%, Parex Resources Colombia Ltd (formerly Ranshorn) with 45% and Verano Royalty rate Energy Limited (Barbados) with 10% working interest. Verano Energy Limited 8% (Barbados) is controlled by Parex Resources. 8-20% 20% We are currently in the exploitation period of the Llanos 34 Block E&P contract 20-25% with an exploration program in execution over certain areas. The contract 25% provides for a six-year exploration period consisting of two three-year phases. It also provides for a 24-year exploitation period for each commercial area, which In the case of natural gas, the royalties are 80% of the rates presented above begins on the date on which such area is declared commercially viable. The for the exploitation of onshore and offshore fields at depths less than or equal exploitation period may be extended for periods of up to 10 years at a time until to 304.8 meters, and 60% for the exploitation of offshore fields at depths such time as the area is no longer commercially viable and certain conditions are exceeding 304.8 meters. For new discoveries of heavy oil, classified as oil with met. We have presented evaluation programs to the ANH for the Tigana, Jacana an API equal to or less than 15°, the royalties are 75% of the rates presented and Chachalaca and Tilo Fields. We presented the declaration of commerciality above. Additionally, in the event that an exploitation area has produced of Max, Túa and Tarotaro on May 5, May 12 and September 7, 2015, respectively. amounts in excess of an aggregate amount established in the E&P Contract governing such area, the ANH is entitled to receive a “windfall profit,” to be Pursuant to the Llanos 34 Block E&P contract and applicable law, we are paid periodically, calculated pursuant to such E&P Contract. required to pay a royalty to the ANH based on hydrocarbons produced in the Llanos 34 Block. In the Max Field, we pay the ANH a royalty of at least 8%, and In each of the exploration and exploitation periods, we are also obligated to pay in the Tua, Chachalaca and Jacana fields and a royalty of at least 6% in the Max, the ANH a subsoil use fee. During the exploration period, this fee is scaled Tarotaro, Tilo and Tigana fields. Additionally, we are required to pay a subsoil depending on the contracted acreage. During the exploitation period, the fee is use fee to the ANH, which, during the exploration period, is scaled depending assessed on the amount of hydrocarbons produced, multiplied by a specified on the contracted acreage, and which, during the exploitation period, is dollar amount per barrel of oil produced or thousand cubic feet of gas produced. equivalent to the amount of oil we produce multiplied by US$0.1372 per bbl Further, the ANH has the right to receive an additional fee when prices for oil or or the amount of natural gas we produce multiplied by US$0.01372 per mcf. gas, as the case may be, exceed the prices set forth in the relevant E&P Contract. The ANH also has the right to receive an additional fee when prices for oil or 96 GeoPark 20F gas, as the case may be, exceed the prices set forth in the Llanos 34 Block E&P these blocks, determine our working interests in the blocks and appoint the contract. The ANH also has an additional economic right equivalent to 1% of operator of the blocks. These CEOPs are divided into two phases: (1) an production, net of royalties. exploration phase, which is divided into two or more exploration periods, and which begins on the effectiveness date of the relevant CEOP, and (2) an In accordance with the Llanos 34 Block operation contract, when the exploitation phase, which is determined on a per-field basis, commencing on accumulated production of each field, including the royalties’ volume, exceeds the date we declare a field to be commercially viable and ending with the 5 million barrels and the WTI exceeds a defined base price, the Company should term of the relevant CEOP. In order to transition from the exploration phase to deliver to ANH a share of the production net of royalties in accordance with an an exploitation phase, we must declare a discovery of hydrocarbons to the established formula. See Note 31 (b) to our Consolidated Financial Statements. Ministry of Energy. This is a unilateral declaration, which grants us the right to test a field for a limited period of time for commercial viability. If the field Winchester and Luna Stock Purchase Agreement proves commercially viable, we must make a further unilateral declaration to Pursuant to the stock purchase agreement entered into on February 10, 2012, or the Ministry of Energy. In the exploration phase, we are obligated to fulfill a the Winchester Stock Purchase Agreement, we agreed to pay the Sellers a total minimum work commitment, which generally includes the drilling of wells, the consideration of US$30.0 million, adjusted for working capital. Additionally, performance of 2D or 3D seismic surveys, minimum capital commitments and under the terms of the Winchester Stock Purchase Agreement, we are obligated guaranties or letters of credit, as set forth in the relevant CEOP. We also have to make certain payments to the Sellers based on the production and sale of relinquishment obligations at the end of each period in the exploration phase hydrocarbons discovered by exploration wells drilled after October 25, 2011. in respect of those areas in which we have not made a declaration of discovery. The agreement provided for us to make a quarterly payment to the Sellers in an We can also voluntarily relinquish areas in which we have not declared amount equal to 14% of adjusted revenue (as defined under the agreement) discoveries of hydrocarbons at any time, at no cost to us. In the exploitation from any new discoveries of oil, up to the maximum earn-out amount of phase, we generally do not face formal work commitments, other than the US$35.0 million (net of Colombian taxes), which was reached in 2015. Once the development plans we file with the Chilean Ministry of Energy for each field maximum earn-out amount is reached, we pay the Sellers quarterly overriding declared to be commercially viable. royalties in an amount equal to 4% of our net revenues from any new discoveries of oil. For the year ended December 31, 2015, we accrued and paid Our CEOPs provide us with the right to receive a monthly remuneration from US$7.1 million and US$9.2 million with regards to this agreement. Chile, payable in petroleum and gas, based either on the amount of petroleum Cuerva purchase and sale agreement and gas production per field or according to Recovery Factor, which considers the ratio of hydrocarbon sales to total cost of production (capital expenditures Pursuant to the purchase and sale agreement dated March 26, 2012 between plus operating expenses). Pursuant to Chilean law, the rights contained in a Hupecol Cuerva Holdings LLC, as the Seller, and us, we paid to the Seller a total CEOP cannot be modified without consent of the parties. consideration of US$75 million, adjusted for working capital. Trafigura offtake and prepayment agreement Our CEOPs are subject to early termination in certain circumstances, which vary depending upon the phase of the CEOP. During the exploration phase, In December 2015, we entered into an offtake and prepayment agreement Chile may terminate a CEOP in circumstances including a failure by us to with Trafigura. The agreement provides that we sell and deliver a portion of comply with minimum work commitments at the termination of any our Colombian crude oil production to Trafigura. This will benefit us by (i) exploration period, or a failure to communicate our intention to proceed with improving crude oil sales prices; (ii) improving operating netbacks by reducing the next exploration period 30 days prior to its termination, a failure to provide transportation costs; (iii) simplifying logistics and reducing risks; and (iv) the Chilean Ministry of Energy the performance bonds required under the improving working capital. Pricing will be determined at future spot market CEOP, a voluntary relinquishment by us of all areas under the CEOP or a failure prices, net of transportation costs. The agreement also gives us access to by us to meet the requirements to enter into the exploitation phase upon the funding up to US$100 million from Trafigura, subject to applicable volumes termination of the exploration phase. In the exploitation phase, Chile may corresponding to the terms of the agreement, in the form of prepaid future oil terminate a CEOP if we stop performing any of the substantial obligations sales. Funds committed by Trafigura will be made available to us upon request assumed under the CEOP without cause and do not cure such and will be repaid by us through future oil deliveries over the period of the nonperformance pursuant to the terms of the concession, following notice of contract, which is 2.5 years with a 6-month grace period. breach from the Chilean Ministry of Energy. Additionally, Chile may terminate Chile CEOPs the CEOP due to force majeure circumstances (as defined in the relevant CEOP). If Chile terminates a CEOP in the exploitation phase, we must transfer to Chile, free of charge, any productive wells and related facilities, provided that We have entered into six CEOPs with Chile, one for each of the blocks in which such transfer does not interfere with our abandonment obligations and we operate, which grant us the right to explore and exploit hydrocarbons in excluding certain pipelines and other assets. Other than as provided in the GeoPark 97 relevant CEOP, Chile cannot unilaterally terminate a CEOP without due correspond to 1 exploratory well until November 7, 2017 for approximately compensation. See “Item 3. Key Information-D. Risk factors-Risks relating to our US$2.1 million, to be assumed 100% by us. business-Our contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating The hydrocarbon discoveries opened up an exploitation phase that lasts up to conditions, and our CEOPs, E&P Contracts and concession agreements are 32 years. We discovered hydrocarbon fields in the 3 blocks, starting 2013 in the subject to early termination in certain circumstances.” Flamenco Block, and in 2014 in both Campanario and Isla Norte Blocks. The CEOPs provide us with a right to receive a remuneration payable by means of Fell Block CEOP. On November 5, 2002, we acquired a percentage of rights a fraction of the production sold, which in the TDF Blocks is based on a formula and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, depending on the recovery of the total accumulated expenses incurred and on May 10, 2006, we became the sole owners, with 100% of the rights (capital expenditure plus operational expenditure plus administrative and and interest in the Fell Block CEOP. Chile had originally entered into a CEOP general expenses). While the recovery factor is less than 1.0, the remuneration for the Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April is 95% of the hydrocarbons produced, either oil or gas. If the recovery factor 29, 1997, which had an effective date of August 25, 1997. The Fell Block CEOP surpasses 1.0, a formula applies reducing gradually the remuneration fraction grants us the exclusive right to explore and exploit hydrocarbons in the Fell to a minimum of 75% when the recovery factor is 2.5 times the total Block and has a term of 35 years, beginning on the effective date. The Fell accumulated expenses . Block CEOP provided for a 14-year exploration period, composed of numerous phases that ended in 2011, and an up-to-35-year exploitation Brazil phase for each field. Rio das Contas Quota Purchase Agreement Pursuant to the Rio das Contas Quota Purchase Agreement we entered into on The Fell Block CEOP provides us with a right to receive a monthly retribution May 14, 2013, we agreed to acquire from Panoro all of the quotas issued by Rio from Chile payable in petroleum and gas, based on the following per-field das Contas for a purchase price of US$140 million (subject to working capital formula: 95% of the oil produced in the field, for production of up to 5,000 adjustments at closing and further earn-out payments, if any) upon bopd, ring fenced by field, and 97% of gas produced in the field, for production satisfaction of certain conditions. With respect to the earn-out payments, the of up to 882.9 mmcfpd. In the event that we exceed these levels of production, Rio das Contas Quota Purchase Agreement provides that during the calendar our monthly retribution from Chile will decrease based on a sliding scale set periods beginning on January 1, 2013 and ending as late as December 31, forth under the Fell Block CEOP to a maximum of 50% of the oil and 60% of 2017, we will make annual earn-out payments to Panoro in an amount equal the gas that we produce per field. to 45% of “net cash flow,” calculated as EBITDA less the aggregate of capital expenditures and corporate income taxes, with respect to the BCAM-40 TDF Blocks CEOPs. After an international bidding process led by ENAP and the Concession of any amounts in excess of US$25.0 million, up to a maximum Chilean Ministry of Energy, in March and April, 2012, we, together with ENAP, cumulative earn-out amount of US$20.0 million in a five-year period. Once the signed 3 new CEOPs for the Blocks Isla Norte, Campanario and Flamenco, all of maximum earn-out amount is reached or the five-year period has elapsed, no them located in Tierra del Fuego (“TDF”), Magallanes region. Our working further earn-out amounts will be payable. For the year ended December 31, interest is 60% in Isla Norte and 50% in Campanario and Flamenco Blocks. The 2015, there were no earn-out payments with regards to this agreement. CEOPs have a term of 32 years, with an initial exploration phase which last for 7 years, including a first exploration period of 3 years in which we are committed We financed our Rio das Contas acquisition in part through our Brazilian to developing several exploration activities including 1,500 square kilometers subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas of 3D seismic registration, and the drilling of 21 exploratory wells. On June 9, Credit Facility”) with Itaú BBA International plc, which is secured by the 2015, ENAP and we asked the Ministry for an extension period of 18 months benefits we receive under the Purchase and Sale Agreement for Natural Gas for the first exploration period for the Campanario and Isla Norte Blocks, in with Petrobras. The facility matures five years from March 28, 2014, with order to re-evaluate the preliminary results of the drilling campaign and to principal annual payments in March and September starting in 2015 and bears add new exploration objectives to the original geological plan. This proposal interest at a variable interest rate equal to the 6-month LIBOR + 3.9%. In March was approved by the Ministry of Energy on August 18, 2015, then the 2015, we reached an agreement to: (i) extend the principal payments that were exploration phase of Campanario and Isla Norte Blocks last 8.5 years including due in 2015 (amounting to approximately US$15 million), which will be a first exploration period of 4.5 years. divided pro-rata during the remaining principal installments, starting in March 2016 and (ii) to increase the variable interest rate equal to the 6-month LIBOR The first exploration period of the Flamenco Block ended in November 2015, + 4.0%. The facility agreement includes customary events of default, and and we and ENAP notified the Ministry of Energy of our decision to continue subjects our Brazilian subsidiary to customary covenants, including the with the second exploration period, which will last for 2 years. As of the date of requirement that it maintain a ratio of net debt to EBITDA of up to 3.5x the first this annual report, outstanding investment commitments related to this block two years and up to 3.0x thereafter. The credit facility also limits the borrower’s 98 GeoPark 20F ability to pay dividends if the ratio of net debt to EBITDA is greater than 2.5x. including responsibility for environmental damages; (2) compliance with the We have the option to prepay the facility in whole or in part, at any time, requirements relating to acquisition of assets and services from domestic subject to a pre-payment fee to be determined under the contract. suppliers; (3) compliance with the requirements relating to execution of the Overview of concession agreements minimum exploration program proposed in the winning bid; (4) activities for the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments The Brazilian oil and gas industry is governed mainly by the Brazilian Petroleum for government participation; and (7) responsibility for the costs associated Law, which provides for the granting of concessions to operate petroleum and with the deactivation and abandonment of the facilities in accordance with gas fields in Brazil, subject to oversight by the ANP. A concession agreement is Brazilian law and best practices in the oil industry. divided into two phases: (1) exploration and (2) development and production. The exploration phase, which is further divided into two subsequent exploratory A concessionaire is required to pay to the Brazilian government the following: periods, the first of which begins on the date of execution of the concession • a license fee; agreement, can last from three to eight years (subject to earlier termination • rent for the occupation or retention of areas; upon the total return of the concession area or the declaration of commercial • a special participation fee; viability with respect to a given area), while the development and production • royalties; and phase, which begins for each field on the date a declaration of commercial • taxes. viability is submitted to the ANP, can last up to 27 years. Upon each declaration of commercial viability, a concessionaire must submit to the ANP a development Rental fees for the occupation and maintenance of the concession areas are plan for the field within 180 days. The concessions may be renewed for an payable annually. For purposes of calculating these fees, the ANP takes into additional period equal to their original term if renewal is requested with at least consideration factors such as the location and size of the relevant concession, 12 months’ notice, and provided that a default under the concession agreement the sedimentary basin and the geological characteristics of the relevant has not occurred and is then continuing. Even if obligations have been fulfilled concession. under the concession agreement and the renewal request was appropriately filed, renewal of the concession is subject to the discretion of the ANP. A special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or The main terms and conditions of a concession agreement are set forth in profitability from oil fields, according to criteria established by applicable Article 43 of the Brazilian Petroleum Law, and include: (1) definition of the regulations, and is payable on a quarterly basis for each field from the date on concession area; (2) validity and terms for exploration and production which extraordinary production occurs. This participation fee, whenever due, activities; (3) conditions for the return of concession areas; (4) guarantees to be varies between 0% and 40% of net revenues depending on (1) the volume of provided by the concessionaire to ensure compliance with the concession production and (2) whether the concession is onshore or in shallow water or agreement, including required investments during each phase; (5) penalties in deep water. Under the Brazilian Petroleum Law and applicable regulations the event of noncompliance with the terms of the concession agreement; (6) issued by the ANP, the special participation fee is calculated based on the procedures related to the assignment of the agreement; and (7) rules for the quarterly net revenues of each field, which consist of gross revenues calculated return and vacancy of areas, including removal of equipment and facilities and using reference prices established by the ANP (reflecting international prices the return of assets. Assignments of participation interests in a concession are and the exchange rate for the period) less: subject to the approval of the ANP, and the replacement of a performance guarantee is treated as an assignment. • royalties paid; • investment in exploration; The main rights of the concessionaires (including us in our concession • operational costs; and agreements) are: (1) the exclusive right of drilling and production in the • depreciation adjustments and applicable taxes. concession area; (2) the ownership of the hydrocarbons produced; (3) the right to sell the hydrocarbons produced; and (4) the right to export the The Brazilian Petroleum Law also requires that the concessionaire of onshore hydrocarbons produced. However, a concession agreement set forth that, in fields pay to the landowners a special participation fee that varies between the event of a risk of a fuel supply shortage in Brazil, the concessionaire must 0.5% to 1.0% of the net operational income originated by the field production. fulfill the needs of the domestic market. In order to ensure the domestic supply, the Brazilian Petroleum Law granted the ANP the power to control the BCAM-40 Concession Agreement. On August 6, 1998, the ANP and Petrobras export of oil, natural gas and oil products. executed the concession agreement governing the BCAM-40 Concession, or Among the main obligations of the concessionaire are: (1) the assumption of referred to as Bid Round Zero, under the regime established by the Brazilian costs and risks related to the exploration and production of hydrocarbons, Petroleum Law. The exploration phase will end in November 2029. On the BCAM-40 Concession Agreement, following the first round of bidding, GeoPark 99 September 11, 2009, Petrobras announced the termination of BCAM-40 Basin in the state of Rio Grande do Norte and two were in the Reconcavo Basin Concession’s exploration phase and the return of the exploratory area of the concession to the ANP, except for the Manati Field and the Camarăo Norte Field. in the state of Bahia. The exploratory phase for these concessions is divided into two exploratory 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. Under the BCAM-40 Concession Agreement, the ANP is entitled to a monthly royalty payment equal to 7.5% of the production of oil and natural gas in the During bidding, a work program offer is made in the form of work units and concession area. In addition, in case the special participation fee of 10% shall the ANP asks for a guarantee of a monetary amount proportional to the be applicable for a field in any quarter of the calendar year, the concessionaire offered units. However, depending on the work performed by the operator, the is obliged to make qualified research and development investments actual work program investment might have a different value to the equivalent to one percent of the field’s gross revenue. Area retention guaranteed value. payments are also applicable under the concession agreement. We acquired Rio das Contas’s 10% participation interest in the BCAM-40 Concession on Overview of consortium agreements March 31, 2014. Round 11 Concession Agreements. A consortium agreement is a standard document describing consortium members’ respective percentages of participation and appointment of the operator. It generally provides for joint execution of oil and natural gas Additionally, on May 14, 2013, following the 11th oil and gas bidding round exploration, development and production activities in each of the concession pursuant to the Brazilian Petroleum Law, we were awarded seven new areas. These agreements set forth the allocation of expenses for each of the exploratory licenses in Brazil in the REC-T 94 and REC-T 85 Concessions in the parties with respect to their respective participation interests in the Recôncavo Basin in the State of Bahia and the POT-T 664, POT-T 665, POT-T concession. The agreements are supplemented by joint operating agreements, 619, POT-T 620 and POT-T 663 Concessions in the Potiguar Basin in the State of which are private instruments that typically regulate the aggregation of funds, Rio Grande do Norte. We have entered into seven concession agreements, the sharing of costs, mitigation of operational risks, preemptive rights and the which we collectively refer to as the Round 11 Concession Agreements, with operator’s activities. the ANP on September 17, 2013, for the right to exploit the oil and natural gas in these seven new license areas. An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph 1, Under the Round 11 Concession Agreements, the ANP is entitled to a monthly of the Brazilian Corporate Law) is the joint liability among consortium royalty corresponding to 10% of the production of oil and natural gas in the members as established in the Brazilian Petroleum Law (Article 38, item II). concession area, in addition to the special participation fee described above, the payment for the occupation of the concession area of approximately R$7,600 per year and the payment to the owners of the land of the concession equivalent to one percent of the oil and natural gas produced in the concession area. Round 12 concession agreements. BCAM-40 Consortium Agreement On January 14, 2000, Petrobras, QG Perfuraçơes and Petroserv entered into a consortium agreement, or the BCAM-40 Consortium Agreement, for the performance of the BCAM-40 Concession Agreement. Petrobras is the operator of the BCAM-40 concession, with a 35% participation interest. QGEP, Brasoil On November 28, 2013, following the 12th oil and gas bidding round pursuant and Rio das Contas have a 45%, 10% and 10% participation interest, to the Brazilian Petroleum Law, we were awarded two new exploratory licenses respectively. The BCAM-40 Consortium Agreement has a specified term of 40 in Brazil, the PN-T-597 Concession on the Parnaiba Basin in the State of Maranhăo and the SEAL-T-268 Concession in the Sergipe-Alagoas Basin in the State of Alagoas. years, terminating on January 14, 2040 and, at the time the obligations undertaken in the agreement are fully completed, the parties will have the right to terminate it. The BCAM-40 Concession consortium has also entered into a joint operating agreement, which sets out the rights and obligations of Part of our bid for the Round 12 concessions was comprised of work program the parties in respect of the operations in the concession. guarantees, or commitments to invest certain sums in the blocks as part our exploration activities. Petrobras Natural Gas Purchase Agreement See “Item 3. Key information-D. Risk factors-Risks relating to our business-The agreement providing for the sale of natural gas by QGEP, GeoPark Brasil and PN-T-597 may not close” for more information. Brasoil to Petrobras, in an amount of 812 billion cubic feet (“bcf”) over the term QGEP, GeoPark Brasil, Brasoil and Petrobras are party to a natural gas purchase Round 13 Concessions of agreement. The Petrobras Natural Gas Purchase Agreement is valid until the earlier of Petrobras’ receipt of this total contractual quantity or June 30, 2030. On October 7, 2015, following the round 13 oil and gas bidding round, we The agreement may not be fully or partially assigned except upon execution were awarded four exploratory concessions, of which two were in the Potiguar of an assignment agreement with the written consent of the other parties, 100 GeoPark 20F which consent may not be unreasonably withheld provided that certain of the President of Peru. Final closing of this transaction is subject to approval prerequisites have been met. by the Peruvian government. The agreement provides for the provision of “daily contractual quantities” to The agreement includes a work program and development plan, for Situche Petrobras, in the following amounts: from the first year through the end of the Central oil field, in the Morona Block, to be completed in stages. Initial stage fourth year under the contract, 211.9 mmcfpd; from the beginning of the fifth goal will be to start production through a long term test, which also will be year through the end of the ninth year, 141.3 mmcfpd; and from the beginning used to define the most effective development plan and to start generating of the tenth year through the end of the contract, 141.3 mmcfpd or such cash flow. We have committed to carry Petroperu’s share of the capital smaller quantity as stipulated by the parties, to take into account the Manati expenses required to carry out the long term test in the wells SC2X and SC3X. Field’s depletion. Pursuant to the agreement, the base price is denominated in The subsequent work program stages, which will be initiated once production reais and is adjusted annually for inflation pursuant to the general index of has been established, are focused on carrying out the full development of the market prices (IGPM). Additionally, the gas price applicable on a given day is Situche Central field, including transportation infrastructure. Petroperu will subject to reduction as a result of the gas quantity acquired by Petrobras also have the right to increase its working interest in the block up to 50%, above the volume of the annual TOP commitment (85% of the daily subject to us recovering our investments in the block by certain agreed contracted quantity) in effect on such day. factors. See “Item 4. Information on the Company-B. Business overview-Our operations-Operations in Peru-Morona Block.” The Petrobras Natural Gas Purchase Agreement provides that if the Manati Field’s daily production capacity is less than the amount of the applicable daily Argentina contractual quantity, gas sales shall be made exclusively to Petrobras, with any Overview of exploitation concessions sales to third parties subject to a penalty. If the field’s production is above the As concession holder of the Del Mosquito Concession, we are subject to applicable daily contractual quantity, the agreement provides that Petrobras numerous restrictions and fees related to hydrocarbon production and foreign must first be offered to purchase the excess amount of gas. markets. For example, oil and gas supply in Argentina must grant a privilege to the domestic market, to the detriment of the export market, including Petrobras Natural Gas Condensate Purchase Agreement hydrocarbon export restrictions, domestic price controls, export duties and On January 1, 2014, Rio das Contas and Petrobras entered into an agreement, domestic market supplier obligations. We are also subject to certain foreign the Petrobras Natural Gas Condensate Purchase Agreement, which after currency retention restrictions. We must maintain a minimum one-year residency certain amendments is valid until December 31, 2017 for the sale to Petrobras in Argentina. We also must comply with central bank registration requirements; of Rio das Contas’s share of the total volume of natural gas condensate to be including the requirement that 30% of all funds remitted to Argentina remain produced in the Manati Field. The agreement can be renewed and takes into deposited in a domestic financial institution for one year without yielding consideration market factors that affect the production and sale of gas. interest, unless such funds are invested in exploration and production or meet other limited requirements, as established under Presidential Decree 616/2005. Pursuant to the agreement, for each liquid barrel of condensed natural gas sold by Rio das Contas, Petrobras will pay the monthly arithmetic average of In general, our Argentina Del Mosquito Block concession grants us the the averages of the daily prices for the “BRENT DTD” barrel, as published by exclusive right to explore and produce hydrocarbons in the block for 25 years, Platt’s Crude Oil Marketwire, subject to a discount of US$2.87 per barrel. with an optional extension of up to 10 years. We also receive the right to be Any assignment of a party’s interest under the agreement requires the other or other transport facilities beyond the boundaries of the concession. There is granted a 35-years oil transport concession to build and make use of pipelines party’s prior written consent. Peru Morona Block Acquisition no minimum work or investment commitment under any of the concessions other than the general requirement to make needed investments in order to develop the entire acreage of the concession, though the regulatory authority takes into account all works and investment undertaken when determining On October 1, 2014, we entered into an agreement with Petroperu to acquire whether to grant an extension of the concession term. Work and investment an interest in and operate the Morona Block, located in Northern Peru. We will programs for the concessions are required to be presented annually to the assume a 75% working interest of the Morona Block, with Petroperu retaining incumbent Provincial State enforcement authority, the Argentine Secretariat of a 25% working interest. Energy and the Strategic Planning and Coordination Committee for the The transaction is subject to conditions precedents, which include the our qualification by Perupetro, which has already been fulfilled, certain Under the terms of our concession agreements, we are entitled to 100% of modifications to the License Contract and the enactment of a Supreme Decree production, with no governmental participation. We are also required, under National Hydrocarbon Investment Plan. GeoPark 101 Argentine law, to pay a 12% royalty to the province on both oil and gas sales. Shareholders’ Agreement and the LGI Colombia Members’ Agreement In addition to this 12% royalty, we are also obliged to pay additional royalties collectively as the LGI Colombia Agreements. ranging from 2.5% to 8%, pursuant to private royalty agreements we have entered into. We also pay annual surface rental fees established under Under the LGI Colombia Agreements, LGI agreed to assume its share of the Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and Resolution 588/98 of existing debt of GeoPark Colombia SAS and to provide additional funding to the Argentine Secretariat of Energy and Decree 1454/2007, and certain cover LGI’s share of required future investments in Colombia through GeoPark landowner fees. Colombia SAS. In addition, we can earn back up to 12% additional equity interests in GeoPark Colombia depending on the success of our Colombian Our Argentine concession agreements have no change of control provisions, operations. though any assignment of these concessions is subject to the prior authorization by the executive branch of the incumbent Provincial State. For Currently, GeoPark Colombia Coöperatie has four directors, out of which one the four years prior to the expiration of each of these concessions, the Director is elected by LGI. The LGI Colombia Agreements require the consent concession holder must provide technical and commercial justifications for of LGI or the LGI-appointed director for GeoPark Colombia SAS to take certain leaving any inactive and non-producing wells unplugged. Each of these actions, including, among others: concessions can be terminated for default in payment obligations and/or • making any decision to terminate or permanently or indefinitely suspend breach of material statutory or regulatory obligations. We may also voluntarily operations in or surrender our blocks in Colombia (other than as required relinquish acreage to the provincial authorities. For example, in November under the terms of the relevant concessions for such blocks); 2012, we voluntarily relinquished approximately 102,500 non-producing gross • creating of a security interest over our blocks in Colombia; acres in the Del Mosquito Block to the provincial authorities, which • approving of GeoPark Colombia’s annual budget and work programs and the relinquishment is currently subject to approval by the authorities of the mechanisms for funding any such budget or program; province of Santa Cruz and the completion of certain environmental audits. • entering into of any borrowings other than those provided in an approved budget or incurred in the ordinary course of business to finance working Our Argentine concessions are governed by the laws of Argentina and the capital needs; resolution of any disputes must be sought in the Federal Courts, although • granting any guarantee or indemnity to secure liabilities of parties other than provincial courts may have jurisdiction over certain matters. those of our Colombian subsidiaries; Agreements with LGI LGI Colombia Agreements • changing the dividend, voting or other rights that would give preference to or discriminate against the shareholders of GeoPark Colombia; • entering into certain related party transactions; and In December 2012, we agreed with LGI to extend our strategic partnership to • disposing of any material assets other than those provided for in an build a portfolio of upstream oil and gas assets throughout Latin America. approved budget and work program. On December 18, 2012, LGI agreed to acquire a 20% equity interest in GeoPark Colombia SAS for a total consideration of US$20.1 million We have also agreed to ensure that the board of directors and rules and composed of a US$14.9 million capital contribution, a US$4.9 million loan to management of our other subsidiaries engaged in our Colombian oil and gas GeoPark Colombia SAS and miscellaneous reimbursements. Concurrently, we business are subject to the same principles and restrictions outlined above. entered into a shareholders’ agreement with LGI (“LGI Colombia Shareholders’ Agreement”) setting forth LGI’s and our respective obligations The LGI Colombia Agreements provide that if either we or LGI decide to sell in connection with LGI’s investment in our Colombian oil and gas business our respective participation in GeoPark Colombia Coöperatie, the transferring through GeoPark Colombia SAS. Furthermore, LGI and Winchester (now party must make an offer to sell its participation to the other party before GeoPark Colombia SAS) entered into a loan agreement, whereby, upon the selling those shares to a third party. In addition, any sale to a third party is closing of LGI’s subscription of shares in GeoPark Colombia SAS, LGI granted subject to tag-along and drag-along rights, and the non-transferring party has a credit line (of which US$4.9 million was drawn at closing) to Winchester of the right to object to a sale to the third-party if it considers such third-party to up to US$12.0 million, to be used for the acquisition, development and be not of a good reputation or one of our direct competitors. operation of oil and gas assets in Colombia. Further, on January 8, 2014, following an internal corporate reorganization of our Colombian operations, Under the LGI Colombia Agreements, we have agreed, along with LGI, to vote GeoPark Colombia Coöperatie U.A. and GeoPark Latin America entered into a or otherwise cause GeoPark Colombia SAS to declare dividends only after new members’ agreement with LGI, or the LGI Colombia Members’ allowing for retentions for approved work programs and budgets and capital Agreement, that sets out substantially similar rights and obligations to the adequacy requirements of GeoPark Colombia Coöperatie, working capital LGI Colombia Shareholders’ Agreement in respect of our oil and gas business requirements, banking covenants associated with any loan entered into by through GeoPark Colombia SAS only. We refer to the LGI Colombia GeoPark Colombia Coöperatie and its subsidiary. See “Item 3. Key 102 GeoPark 20F Information-D. Risk factors-Risks relating to our business-LGI, our strategic and the non-transferring shareholder has the right to object to a sale to the partner in Chile and Colombia, may not consent to our taking certain actions third-party if it considers such third-party to be not of a good reputation or or may eventually decide to sell its interest in our Chilean and Colombian one of our direct competitors. Under the LGI Chile Shareholders’ Agreements, operations to a third party.” LGI Chile Shareholders’ Agreements we and LGI have also agreed to vote our common shares or otherwise cause 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 In 2010, we formed a strategic partnership with LGI to jointly acquire and obligations. See “Item 3. Key Information-D. Risk factors-Risks relating to our develop upstream oil and gas projects in Latin America. In 2011, LGI acquired business-LGI, our strategic partner in Chile and Colombia, may not consent to a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark our taking certain actions or may eventually decide to sell its interest in our TdF, for a total consideration of US$148.0 million, plus additional equity Chilean and Colombian operations to a third party.” funding of US$18.0 million over the following three years. On May 20, 2011, in connection with LGI’s investment in GeoPark Chile, we entered into a Title to properties shareholders’ agreement with LGI (as amended on July 4, 2011 and October 4, In each of the countries in which we operate, the state is the exclusive owner 2011, the “GeoPark Chile Shareholders’ Agreement”) and a subscription of all hydrocarbon resources located in such country and has full authority to agreement (as amended on July 4, 2011 and October 4, 2011), On October determine the rights, royalties or compensation to be paid by private investors 2011, in connection with LGI’s investment in GeoPark TdF, we entered into a for the exploration or production of any hydrocarbon reserves. In Chile, the shareholder´s agreement with LGI (the “GeoPark TdF Shareholders Republic of Chile grants such rights through a CEOP. In Colombia, the Republic Agreement”, and together with the GeoPark Chile Shareholders’ Agreement, of Colombia grants such rights through E&P Contracts or contracts of the “LGI Chile Shareholders’ Agreements”), setting forth LGI’s and our association. In Argentina, the Argentine Republic grants such rights through respective rights and obligations in connection with LGI’s investment in our exploitation concessions. In Brazil, the Federative Republic of Brazil grants such Chilean oil and gas business. rights pursuant to concession agreements. See “Item 3. Key Information-D. Risk factors-Risks relating to the countries in which we operate-Oil and natural gas The respective boards of each of GeoPark Chile and GeoPark TdF supervise companies in Colombia, Chile, Brazil, Peru and Argentina do not own any of the their day-to-day operations. Each of these boards has four directors. As long as oil and natural gas reserves in such countries.” Other than as specified in this LGI holds at least 5% of the voting shares of GeoPark Chile, LGI has the right to annual report, we believe that we have satisfactory rights to exploit or benefit elect one director and such director’s alternate, and the remaining directors, economically from the oil and gas reserves in the blocks in which we have an and alternates, are elected by us. As long as LGI holds at least 5% of the voting interest in accordance with standards generally accepted in the international shares of GeoPark TdF, LGI has the right to elect one director and such oil and gas industry. Our CEOPs, E&P Contracts, contracts of association, director’s alternate, and the remaining directors, and alternates, are elected by exploitation concessions and concession agreements are subject to customary GeoPark Chile. royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry The LGI Chile Shareholders’ Agreements require the consent of LGI or the LGI that we believe do not materially interfere with the use of or affect the appointed director in order for GeoPark Chile and GeoPark TdF, as the case carrying value of our interests. See “Item 3. Key Information-D. Risk factors-Risks may be, to take certain actions, including, among others: relating to our business-We are not, and may not be in the future, the sole • making any decision to terminate or permanently or indefinitely suspend owner or operator of all of our licensed areas and do not, and may not in the operations in or surrender our blocks in Chile (other than as required under future, hold all of the working interests in certain of our licensed areas. the terms of the relevant CEOP for such blocks or required by law); Therefore, we may not be able to control the timing of exploration or • selling our blocks in Chile to our affiliates; development efforts, associated costs, or the rate of production of any • any change to the dividend, voting or other rights that would give preference non-operated and, to an extent, any non-wholly-owned, assets.” to or discriminate against the shareholders of GeoPark Chile and GeoPark TdF; • entering into certain related party transactions; and Our customers • creating a security interest over our blocks in Chile (other than in connection In Chile, our primary customers are ENAP and Methanex. As of December 31, with a financing that benefits our Chilean subsidiaries). 2015, ENAP purchased all of our oil and condensate production and Methanex The LGI Chile Shareholders’ Agreements provide that if LGI or either Agencia or 15% and 7%, respectively, of our total revenues for the year ended December GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark TdF, as the 31, 2015. Our contract with ENAP is automatically renewed for 6-month terms, case may be, the transferring shareholder must make an offer to sell those with oil pricing based on international market prices. Our contract with shares to the other shareholder before selling those shares to a third party. In Methanex is a long-term contract, with the price of natural gas based on the addition, any sale to a third party is subject to tag-along and drag-along rights, international market prices for methanol. In Colombia, our primary customers purchased almost all of our natural gas production in Chile, and represented GeoPark 103 are Gunvor, Trafigura and Petrominerales, who purchase our production industry is intense, which makes it difficult for us to attract capital, acquire through short-term contracts, and who represented 39.1%, 7.9%, and 5.8%, properties and prospects, market oil and natural gas and secure trained respectively, of our total revenues for the year ended December 31, 2015. In personnel.” Brazil, following the Manati acquisition on March 31, 2014, all of our hydrocarbons are sold to Petrobras. In Peru, our primary customer may be We are also affected by competition for drilling rigs and the availability of Petroperu, who has the first option but not the obligation to purchase oil related equipment. Higher commodity prices generally increase the demand produced by us in the Morona Block. Seasonality for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past several years, oil and natural gas companies have Although there is some historical seasonality to the prices that we receive for experienced higher drilling and operating costs. Shortages of, or increasing our production, the impact of such seasonality has not been material. costs for, experienced drilling crews and equipment and services could restrict Additionally, seasonality does not play a significant role in our ability to our ability to drill wells and conduct our operations. conduct our operations, including drilling and completion activities. Although in winter months, it is more difficult or even impossible to conduct certain of Health, safety and environmental matters our operations, such as seismic work, we take such seasonality into account in General planning for and conducting our operations, such that the impact on our Our operations are subject to various stringent and complex international, overall business is not material. federal, state and local environmental, health and safety laws and regulations Our competition in the countries in which we operate governing matters including the emission and discharge of pollutants into the ground, air or water; the The oil and gas industry is competitive, and we may encounter strong generation, storage, handling, use and transportation of regulated materials; competition from other independent operators and from major oil companies and human health and safety. These laws and regulations may, among other in acquiring and developing licenses. In Chile, we partner with and sell to, and things: may from time to time compete with, ENAP and, to a lesser extent, some • require the acquisition of various permits or other authorizations or the companies with operations in Argentina mentioned below. In Colombia, we preparation of environmental assessments, studies or plans (such as well partner with and sell to, and may from time to time compete with, Ecopetrol, closure plans) before seismic or drilling activity commences; as well as with privately-owned companies such as Pacific Rubiales, Gran Tierra, • enjoin some or all of the operations of facilities deemed not in compliance Petrominerales, Parex and Canacol, among others. In Brazil, we partner with with permits; and sell to, and may from time to time compete with, Petrobras, privately- • restrict the types, quantities and concentration of various substances that can owned companies such as HRT, QGEP, Brasoil and some of the Colombian be released into the environment in connection with oil and natural gas companies mentioned above, which have entered into Brazil, among others. In drilling, production and transportation activities; Argentina, we compete for resources with YPF, as well as with privately-owned • require establishing and maintaining bonds, reserves or other commitments companies such as Pan American Energy, Pluspetrol, Tecpetrol, Chevron, to plug and abandon wells; Wintershall, Total, Sinopec and others. In Peru, we will partner with and will sell • limit or prohibit seismic and drilling activities in certain locations lying within to, Petroperu and will compete for resources with privately-owned companies or near protected or otherwise sensitive areas; and such as Pluspetrol, Gran Tierra, Repsol, Graña y Montero, Hunt Oil, Olympic Oil • require remedial measures to mitigate or remediate pollution from our & Gas, Savia, among others; and with state-owned oil companies as CNPC operations, which, if not undertaken, could subject us to substantial penalties. (China National Petroleum Corporation). Many of these competitors have financial and technical resources and production below the rate that would otherwise be possible. Compliance with personnel substantially larger than ours. As a result, our competitors may be these laws can be costly. The regulatory burden on the oil and gas industry able to pay more for desirable oil and natural gas assets, or to evaluate, bid for increases the cost of doing business in the industry and consequently affects These laws and regulations may also restrict the rate of oil and natural gas and purchase a greater number of licenses than our financial or personnel profitability. resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of Moreover, public interest in the protection of the environment continues to volatility in financial and commodities markets and generally adverse global increase. Drilling in some areas has been opposed by certain community and and industry-wide economic conditions, and may be better able to absorb the environmental groups and, in other areas, has been restricted. Our operations burdens resulting from changes in relevant laws and regulations, which may could be adversely affected to the extent laws are enacted or other adversely affect our competitive position. See “Item 3. Key Information-D. Risk governmental action is taken that prohibits or restricts seismic or drilling factors-Risks relating to our business-Competition in the oil and natural gas activities or imposes environmental requirements that result in increased costs 104 GeoPark 20F to the oil and gas industry in general, such as more stringent or costly waste (TRIR) was 2.33 (every 1.000.000 worked hours) and we had no fatal incidents handling, disposal or cleanup requirements. related to operations in 2015 (workforce). Climate change Certain Bermuda law considerations Our operations and the combustion of oil and natural gas-based products As a Bermuda exempted company, we and our Bermuda subsidiaries are results in the emission of greenhouse gases, which may contribute to global subject to regulation in Bermuda. We have been designated by the BMA as a climate change. Climate change regulation has gained momentum in recent non-resident for Bermuda exchange control purposes. This designation allows years internationally and at the federal, regional, state and local levels. On the us to engage in transactions in currencies other than the Bermuda dollar, and international level, various nations have committed to reducing their there are no restrictions on our ability to transfer funds (other than funds greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto Protocol denominated in Bermuda dollars) in and out of Bermuda. was set to expire in 2012. In late 2011, an international climate change conference in Durban, South Africa resulted in, among other things, an Under Bermuda law, “exempted” companies are companies formed for the agreement to negotiate a new climate change regime by 2015 that would aim purpose of conducting business outside Bermuda from a principal place of to cover all major greenhouse gas emitters worldwide, including the U.S., and business in Bermuda. As exempted companies, we and our Bermuda take effect by 2020. In November and December 2012, at an international subsidiaries may not, without a license or consent granted by the Minister of meeting held in Doha, Qatar, the Kyoto Protocol was extended by amendment Finance of Bermuda, participate in certain business transactions, including until 2020. In addition, the Durban agreement to develop the protocol’s transactions involving Bermuda landholding rights and the carrying on of successor by 2015 and implement it by 2020 was reinforced. business of any kind for which we or our Bermuda subsidiaries are not licensed Our HSE Management System Our health, safety and environmental management plan is focused on Insurance in Bermuda. undertaking realistic and practical programs based on recognized world We maintain insurance coverage of types and amounts that we believe to be practices. Our emphasis is on building key principles and company-wide customary and reasonable for companies of our size and with similar ownership and then expanding programs as we continue growing. Our operations in the oil and gas industry. However, as is customary in the industry, S.P.E.E.D. philosophy and our HSE Program have been developed with we do not insure fully against all risks associated with our business, either reference to ISO 14001 for environmental management issues, OHSAS 18001 because such insurance is not available or because premium costs are for occupational health and safety management issues, SA 8000 for social considered prohibitive. accountability and workers’ rights issues and applicable World Bank Standards. Our Environmental Policy Currently, our insurance program includes, among other things, construction, fire, vehicle, technical, umbrella liability, director’s and officer’s liability and Our policy is to strive to meet or exceed environmental regulations in the employer’s liability coverage. Our insurance includes various limits and countries in which we operate. We believe that oil and gas can be produced deductibles or retentions, which must be met prior to or in conjunction with in an environmentally-responsible manner with proper care, understanding recovery. A loss not fully covered by insurance could have a materially adverse and management. Within our S.P.E.E.D. program we have a team that is effect on our business, financial condition and results of operations. See “Item exclusively focused on securing the environmental authorizations and 3. Key Information-D. Risk factors-Risks relating to our business-Oil and gas permits for the projects we undertake. This professional and trained team, operations contain a high degree of risk and we may not be fully insured specialized in environmental issues, is also responsible for the achievement against all risks we face in our business.” of the environmental standards set by our Board of Directors and for training and supporting our personnel. Our senior executives, personnel in Industry and regulatory framework the field, visitors and contractors have also received training in proper Global oil and gas industry environmental management. According to the BP Statistical Review of World Energy June 2015 (“BP Statistical Review”), during 2014, global primary energy consumption Our Health and Safety Policy decelerated sharply even though global economic growth was similar to 2013. We believe that the implementation of additional safety tools in our Consumption increased for all fuels, reaching record levels for every fuel type operations in 2015 has significantly contributed to control and minimizing except nuclear power. Production increased for all fuels except coal. For oil and risks in our operations. Actions taken by us included training, permits to work, natural gas, global consumption growth was weaker than production. internal audits, drills, pre-job meetings and job safety analysis. As of December 31, 2015, on the last 12-month basis, our HSE development statistics show that Global primary energy consumption increased by just 0.9% in 2014, a marked Lost Time Injury Frequency (LTIF) was 0.85, our Total Recordable Incident Rate deceleration over 2013 (+2.0%) and well below the 10-year average of 2.1%. GeoPark 105 Growth in 2014 slowed for every fuel other than nuclear power, which was also Distribution of proved natural gas reserves in 1994, 2004 and 2014 the only fuel to grow at an above-average rate. Percentage Global oil consumption grew by 0.8 million barrels per day (0.8%), a little below its recent historical average and significantly weaker than the increase of 1.4 million bopd seen in 2013. Global oil production growth was more than double that of global consumption, rising by 2.1 million bopd or 2.3%. The US (+1.6 million bopd) recorded the largest growth in the world, becoming the first country ever to increase production by at least 1 million bopd for three consecutive years, taking over from Saudi Arabia as the world’s largest oil producer. Along with the US, production in Canada (+310,000 bopd) and Brazil (+230,000 bopd) also reached record levels in 2014. Middle East Europe & Eurasia S. & Cent. America Africa North America Asia Pacific 4.8 7.1 38.2 7.7 8.1 34.1 9.1 8.3 27.3 4.1 42.7 6.5 4.4 46.1 4.8 7.6 8.2 31.0 1994 - Total 119.1 trillion cubic metres 2004 - Total 156.5 trillion cubic metres 2014 - Total 187.1 trillion cubic metres World natural gas consumption grew by just 0.4%, well below the 10-year average of 2.4%. Global natural gas production grew by 1.6%, below its Source: BP Statistical Review 10-year average of 2.5%. Growth was below average in all regions except North America. The industry’s outlook is gradually shifting, driven mainly by supply patterns. According to BP’s Energy Outlook 2035, trade patterns are shifting. The strong Total world proved oil reserves reached 1700.1 billion barrels at the end of growth of US tight oil in recent years has had a dramatic impact, with oil 2014, sufficient to meet 52.5 years of global production. The largest addition to increasingly flowing from West to East rather than East to West. This is likely to reserves came from Saudi Arabia, which added 1.1 billion barrels. The largest continue, with strong growth in China and India driving energy demand. decline came from Russia, where reserves fell by 1.9 billion barrels. OPEC According to the BP Statistical Review, it is also expected that the market in countries continue to hold the majority of the world’s reserves, accounting for gas will become more global as liquefied natural gas integrates regional 71.6% of the global total. South & Central America continues to hold the markets and leads to greater congruence in global price movements. highest R/P ratio, more than 100 years. Over the past decade, global proved reserves have increased by 24%, or more than 330 billion barrels. Second, the energy mix continues to shift. Fossil fuels are projected to provide the majority of the world’s energy needs, meeting two-thirds of the increase in Distribution of proved oil reserves in 1994, 2004 and 2014 energy demand out to 2035. However, the mix will shift. Renewables and Percentage Middle East Europe & Eurasia S. & Cent. America Africa North America Asia Pacific 3.5 5.8 59.4 10.3 12.6 11.4 7.3 16.4 1994 - Total 1118.0 thousand million barrels Source: BP Statistical Review unconventional fossil fuels will take a larger share, along with gas, which is set to be the fastest growing fossil fuel, as well as the cleanest, meeting as much of the increase in demand as coal and oil combined. 2.5 47.7 7.6 3.0 54.9 7.9 9.1 Chile Regulation of the oil and gas industry Under the Chilean Constitution, the state is the exclusive owner of all mineral 13.7 and fossil substances, including hydrocarbons, regardless of who owns the 7.6 2004 - Total 1366.2 thousand million barrels 19.4 2014 - Total 1700.1 thousand million barrels land on which the reserves are located. The exploration and exploitation of hydrocarbons may be carried out by the state, companies owned by the state or private entities through administrative concessions granted by the President of Chile by Supreme Decree or CEOPs executed by the Minister of Energy. Exploitation rights granted to private companies are subject to special taxes and/or royalty payments. The hydrocarbon exploration and exploitation industry is supervised by the Chilean Ministry of Energy. According to the BP Statistical Review, world proven natural gas reserves at end-2014 stood at 187.1 trillion cubic meters (tcm), sufficient to meet 54.1 In Chile, a participant is granted rights to explore and exploit certain assets years of global production. Proved reserves grew by 0.3% relative to the end of under a CEOP. If a participant breaches certain obligations under a CEOP, the 2013. Growth in Russia (+0.4 tcm), Azerbaijan (+0.3 tcm) and the US (+0.2 tcm) participant may lose the right to exploit certain areas or may be required to accounted for all of the gross increase in global proved reserves in 2014. Iran return all or a portion of the awarded areas to Chile with no right of (34.0 tcm) and Russia (32.6 tcm) hold the largest proved reserves. compensation. Although the government of Chile cannot unilaterally modify 106 GeoPark 20F the rights granted in the CEOP once it is signed, exploration and exploitation and the integrity of environmental policy and regulations. The Environmental are nonetheless subject to significant government regulations, such as Assessment Agency is responsible for assessing whether projects that might regulations concerning the environment, tort liability, health and safety and have an adverse effect on the environment comply with Chilean labor. In the past year, for example, the Chilean government has proposed new environmental laws and regulations. The Environmental Assessment Agency regulations regarding the closure plans applicable to hydrocarbon operations directs and coordinates the environmental impact assessment process, whose that could have an impact on the timeframes and costs required to set up final qualification is granted by the competent regional environmental exploration or exploitation activities. assessment commission. The Superintendency of Environment’s primary Regulatory entities responsibilities are monitoring compliance with the terms of an environmental impact assessment, as well as monitoring compliance with The Chilean Ministry of Energy and the National Commission of Energy government plans to prevent environmental damage or to clean or restore (Comisión Nacional de Energía), or the CNE, are the principal government contaminated geographical areas. The Superintendency of Environment has agencies responsible for the issuance of policies and regulations for the oil the power to suspend or terminate, or impose fines from US$1,000 up to and gas sector. The Chilean Ministry of Energy is responsible for monitoring a US$10.0 million for, activities that it deems to have an adverse environmental participant’s compliance with its obligations under a CEOP. The impact, even if such activities comply with a previously approved Superintendency of Electricity and Fuels ( Superintendencia de Electricidad y environmental impact assessment. Combustibles ), or the SDEC, supervises compliance with regulations regarding gas pipeline transportation and the Ministry of Environment, the The Environmental Courts Environmental Assessment Agency and the Superintendency of Environment The Environmental Courts are principally responsible for hearing appeals of are responsible for environmental matters. The new Environmental Courts are decisions made by the Superintendency of Environment and for adjudicating responsible for settling disputes relating to environmental permits, claims claims for environmental damage. There are currently two Environmental against the Superintendency of Environment and claims concerning Courts in Chile, which began to hear claims on December 28, 2012 and on environmental damage. Ministry of Energy October 7, 2013, respectively. There is a third Environmental Court expected to begin hearing claims during 2016. The Environmental Court that will have jurisdiction over the area in which we operate elected its members on The Chilean Ministry of Energy is responsible for developing and coordinating September 12, 2013 and began its operations in October, 2013. all plans, policies and regulations for the energy sector in Chile and supervising and advising the government in all matters related to energy. It Regulatory framework coordinates the different entities in the energy sector in Chile and, by law, its Regulation of exploration and production activities Minister is the chairman of the board of directors of ENAP. The Ministry of Oil and gas exploration and development is governed by the Political Energy is also responsible for the protection, conservation and development Constitution of the Republic of Chile and Decree with Law Force No 2 of 1986 of renewable and non-renewable energy resources. of the Ministry of Mines, which set forth the revised text of the Decree Law SDEC 1089 of 1975, on CEOPS. However, the right to explore and develop fields is granted for each area under a CEOP between Chile and the relevant The SDEC is responsible for monitoring compliance with all regulations related contractors. The CEOP establishes the legal framework for hydrocarbon to the generation, production, storage, transportation and distribution of all activities, including, among other things, minimum investment commitments, fuels, gas and electricity for the consumer market. To enforce such regulations, exploration and exploitation phase durations, compensation for the private the SDEC has the power to impose fines and, if necessary, to take over the company (either in cash or in kind) and the applicable tax regime. Accordingly, administration of deficient services when applicable. Our operations are not all the provisions governing the exploitation and development of our Chilean under the supervision of the SDEC. operations are contained in our CEOPs and the CEOPs constitute all the licenses that we need in order to own, operate, import and export any of the Ministry of Environment, Environmental Assessment Agency and Superintendency equipment used in our business and to conduct our gas and petroleum of Environment operations in Chile. The Ministry of Environment, the Environmental Assessment Agency and the Superintendency of Environment are primarily responsible for environmental Under Chilean law, the surface landowners have no property rights over the issues in Chile, including those affecting the oil and gas industry. The Ministry minerals found under the surface of their land. Subsurface rights do not of Environment is responsible for the formulation and implementation of generate any surface rights, except the right to impose legal easements or environmental policies, plans, programs and regulation, as well as for the rights of way. Easements or rights of way can be individually negotiated with protection and conservation of biological diversity and renewable natural individual surface land owners or can be granted without the consent of the resources and water resources and for promoting sustainable development landowner through judicial process. Pursuant to the Chilean Code of Mines, a GeoPark 107 judge can permit a party to use an easement pending final adjudication and Income in Chile is subject to corporate tax on an accrual basis and has a current settlement of compensation for the affected landowner. rate of 21% for fiscal year 2014. The applicable and invariable corporate income Regulation of transportation activities tax rates of our CEOPs range between 15% and 18.5%, as follows: the Fell Block is subject to a rate of 15%, the Otway and Tranquilo Blocks are subject to a rate Liquid hydrocarbon transportation, storage, importation and marketing are of 17% and the Flamenco, Isla Norte and Campanario Blocks are subject to a subject to a number of technical regulations regarding safety, quality and rate of 18.5% for the income accrued or received during 2012 and 17% for the other matters. The rules for the transportation of liquid fuels through trucks income accrued or received during 2013 and onward. Dividends or profits and pipelines are primarily found in Supreme Decree No. 160 of 2009 (the distributed to the foreign shareholders of the contractors are subject to 35% Safety Code for Facilities and Production and Refining Operations, Additional Withholding Tax with a tax credit for the corporate income tax paid Transportation, Storage, Distribution and Supply of Liquid Fuels) of the by the contractor. With regard to the value added tax, contractors may obtain as Ministry of Economy. The Ministry of Energy is responsible for the regulation of a refund the value added tax (which is 19% according to the Sales and Services transportation by pipeline and the Ministry of Transport is responsible for the Tax Law contained in Decree Law No. 825 of 1974) supported or paid on the regulation of transportation by truck. import or purchase of goods or services used in connection with the exploration and exploitation activities. The applicable tax regime for each CEOP Gas transportation in Chile is subject to open access rules, in which the gas remains unchanged throughout the duration of the CEOP. transportation company must make its excess transportation capacity available to third parties under equal economic, commercial and technical The Chilean Congress approved a reform to the income tax law in September conditions. Laws prohibit the abuse of a dominant position by a gas 2014. Under this reform the income tax rate will increase from 20% in 2013 to: transportation company in order to discriminate among potential customers 21% in 2014, 22.5% in 2015, 24% in 2016, 25.5% in 2017 and 27% in 2018. The for use of its pipelines. Pursuant to Ministry of Economy Supreme Decree No. operating subsidiaries that we control in Chile, which are GeoPark TdF S.A., 280 of 2009, gas pipelines must also comply with the Regulation of Security for GeoPark Fell S.p.A. and GeoPark Magallanes Limitada, are not affected by the Transportation and Distribution of Gas, which regulates the design, income tax reform mentioned since they are covered by the tax treatment construction, operation, maintenance, inspection and termination of established in the CEOPs. operations of a natural gas pipeline. Colombia Additionally, Chile is a signatory state to the Substitute Protocol of the Eighth Regulation of the oil and gas industry Additional Protocol to the Economic Complementation Agreement No. 16 Under Colombian law, the state owns all hydrocarbon reserves discovered in between Chile Republic and Argentina Republic (ACE 16) Regulation for the Colombian territory and exercises control of the exploitation of such Marketing, Operations and Transportation of Hydrocarbons Liquids-Crude Oil, reserves primarily through the ANH. Liquefied Gas and Liquid Products of Petroleum and Natural Gas and the following international conventions: the International Convention for the The ANH is responsible for managing all exploration lands not subject to prevention of Pollution of the Sea by Oil of 1954, the Convention on the previously existing association contracts with Ecopetrol. The ANH began Prevention of Marine Pollution by Dumping of Wastes and Other Matters of offering all undeveloped and unlicensed exploration areas in the country 1972 and the International Convention on Civil Liability for Oil Pollution under E&P Contracts and Technical Evaluation Agreements, or TEAs, which Damage of 1969. Taxation resulted in a significant increase in Colombian exploration activity and competition, according to the ANH. The ANH is also in charge of negotiating and executing contracts through “direct negotiation” mechanisms with With regard to direct taxes on hydrocarbon exploitation, the general rule is that attention to special conditions in the areas to be explored. hydrocarbons are transferred to the contractor (its retribution under the CEOP), and those re-acquisitions from the contractor performed by Chile or its Regulatory entities enterprises, as well as their corresponding acts, contracts and documents, are The principal authorities that regulate our activities in Colombia are the tax exempt. In addition, hydrocarbon exports by the contractor are also tax Ministry of Mines and Energy, the ANH, the National Environmental Licensing exempt. With regard to income taxes, as provided by article 5 of Decree Law No. Authority, or the ANLA, and the Regulatory Commission of Energy and Gas, or 1,089, the contractor is subject either to a single tax calculated on its the CREG. retribution, equal to 50% of such retribution, or to the general income tax regime established in the Income Tax Law (Decree Law No. 824 of 1974), in force Ministry of Mines and Energy at the time of the execution of the public deed which contains CEOPs, terms of The Ministry of Mines and Energy is responsible for managing and regulating which will be applicable and invariable throughout the duration of the contract. Colombia’s nonrenewable natural resources, assuring their optimal utilization 108 GeoPark 20F by defining and adopting national policies regarding exploration, production, Domiciliary Public Services ( Superintendencia de Servicios Públicos transportation, refining, distribution and export of minerals and hydrocarbons. Domiciliarios ). ANH Regulatory framework The ANH was created in 2003 and is responsible for the administration of Regulation of exploration and production activities Colombia’s hydrocarbon reserves. The ANH’s objective is to manage the Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon hydrocarbon reserves owned by the state through the design, promotion and resources located in Colombia and has full authority to determine the rights, negotiation of the exploration and production agreements in areas where royalties or compensation to be paid by private investors for the exploration or hydrocarbons may be found. The ANH is also responsible for creating and production of any hydrocarbon reserves. The Ministry of Mines and Energy is maintaining attractive conditions for private investments in the hydrocarbon the authority responsible for regulating all activities related to the exploration sector and for designing bidding rounds for exploration blocks. and production of hydrocarbons in Colombia. Any oil company selected by the ANH to explore a specific block must execute Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, either a TEA or an E&P Contract to develop and exploit the block with the ANH. establishes the general procedures and requirements that must be completed All royalty payments in connection with the production of hydrocarbons are by a private investor prior to commencing hydrocarbon exploration or made to the ANH in kind unless the ANH grants a specific waiver to make production activities. The Petroleum Code sets forth general guidelines, royalty payments in cash or the specific contract provides for payment in cash. obligations and disclosure procedures that need to be followed during the Any oil company working in Colombia must present to the ANH periodic performance of these activities. reports on the evolution of their exploration and exploitation activities. ANLA Exploration and production activities were governed by Decree 1895 of 1973 until September 2009. Decree Law 2310 of 1974 (as complemented by Decree The ANLA was created pursuant to Decree 3573 of 2011 issued by the 743 of 1975) governed the contracts and contracting processes carried out by Colombian government with the participation of the Administrative Ecopetrol and the rules applicable to such contracts, and also provided that Department of Public Functions ( Departamento Administrativo de la Función Ecopetrol was responsible for administering the hydrocarbons resources in the Pública ), and is responsible for hydrocarbon environmental licensing in Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, but Colombia. Any project in the hydrocarbons sector requiring an environmental all agreements entered into by us prior to 2003 with other oil companies are license must submit to environmental licensing procedures, which require the still regulated by Decree 2310 of 1974. presentation of an environmental impact assessment, an environmental management plan and a contingency plan. Environmental licenses are granted Decree Law 1760 of 2003 provided the faculties, structure and functions of the for exploration and production phases separately. ANH, and granted the ANH full and exclusive authority to regulate and oversee CREG the exploration and production of hydrocarbon reserves. Decree Law 1760 of 2003 was complemented by Decree 2288 of 2004, which regulates all aspects Laws 142 and 143 of 1994 created the CREG, a special administrative unit of related to the reversion of reserves and infrastructure under the joint venture the Ministry of Mines and Energy, responsible for establishing the standards agreements executed by us before 2004. for the exploitation and use of energy, regulating the domestic utilities of electricity and fuel gas (liquefied petroleum gas and natural gas), establishing The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and price rules for energy and gas and regulating self-generation and Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced by cogeneration of energy. The CREG is also responsible for fostering the Accord 004 of 2012, issued by the Directive Council of the ANH, sets forth the development of the energy services industry, promoting competition and necessary steps for entering into E&P Contracts with the ANH. This Agreement responding to consumer and industry needs. Decree 4130 of 2011 assigned only regulates the contracts entered into as of May 4, 2012. Prior contracts are the CREG new functions that were previously fulfilled by the Ministry of Mines still ruled by Agreement 008 of 2004. and Energy, including the regulation of tariffs for oil transportation in poliducts and the regulation of petroleum-derived liquid fluids. Resolution 18-1495 of 2009 establishes a series of regulations regarding Superintendency of Domiciliary Public Services afforded access to non-contracted blocks by committing to an exploration Under Colombian regulations, the distribution and marketing of natural gas is work program. These E&P Contracts provide companies with 100% of new considered a public service. As such, this activity, as well as electricity, are production, less the participation of the ANH, which participation may differ regulated by Law 142 of 1994 and supervised by the Superintendency of for each E&P Contract and depends on the percentage that each company has hydrocarbon exploration and exploitation. In the E&P Contracts, operators are GeoPark 109 offered to the ANH in order to be granted with a block, subject to an initial economic impact, the sources of financing, profitability, social contribution, the royalty payment of 8% and the payment of income taxes of 33%. In addition, effects on Colombia’s balance of payments and the price structure of the the Colombian government also introduced TEAs, in which companies that refined products. enter into TEAs are the only ones to have the right to explore, evaluate and select desirable exploration areas and to propose work commitments on those Pursuant to Resolution 18-0966 of 2006 issued by the Ministry of Mines and areas, and have a preemptive right to enter into an E&P Contract, thereby Energy and Article 58 of the Petroleum Code, any refining company operating providing companies with low-cost access to larger areas for preliminary in Colombia must provide a portion or, if needed, the total of its production to evaluation prior to committing to broader exploration programs. A preemptive supply local demand prior to exporting any production. If the regulated right is granted to convert the TEA into an E&P Contract. Exploration activities production income, the principal item in the price formula, becomes lower than can only be carried out by the TEA contractor. the export parity price, the price paid for the refined products will be equivalent to the price for those products in the U.S. Gulf Coast market. If there is local Pursuant to Colombian law, companies are obligated to pay a percentage of demand for imported crudes, the refining company may charge additional their production to the ANH as royalties and an economic right as ANH’s transportation costs in proportion to the crudes delivered to the refinery. participating interest in the production. In 1999, a modification to the royalty system established a sliding scale for royalty payments, linking them to the In 2008, Law 1205 was issued, with the main purpose of contributing to a production level of crude oil and natural gas fields discovered after July 29, healthier environment, and established the minimum quality that fuels should 1999 and to the quality of the crude oil produced. Since 2002 the royalties have in the country and the time frame for such a purpose. system has ranged from 8% for fields producing up to 5,000 bopd to 25% for fields producing in excess of 600,000 bopd. Changes in royalty programs only The Ministry of Mines and Energy establishes the safety standards for LPG, apply to new discoveries and do not alter fields already in their production storage equipment, maintenance and distribution. Regulations issued in 1992 stage. Producing fields pay royalties in accordance with the applicable royalty established that every local, commercial and industrial facility with a storage program at the time of the discovery. The purchase price is calculated based capacity of LPG greater than 420 pounds must receive authorization for on a reference price for crude oil at the wellhead and varies depending on operations from the Ministry of Mines and Energy. prevailing international prices. Decree 2100 of 2011 modified the commercialization scheme of natural gas royalties. From 2012 and until May As of May 2012, under the powers granted by Decree 4130 of 2011 for 2013, producers had to directly commercialize the royalties of their own currency and tax matters as well as for royalties, the ANH will determine the production on behalf of the ANH. In return, the ANH paid a commercialization crude oil price reference. fee to producers. As of May 2013, contractors must pay in kind royalties to third parties called “Royalty Trading Companies” or “Royalty Marketing Regulation of transportation activities Companies,” which are in charge of commercializing the royalties. Hydrocarbon transportation activity is considered a public utility activity in Colombia and therefore is under governmental supervision and control. It is Regulation of refining and petrochemical activities also a public service, and pipelines are considered to be public transport Refining and petrochemical activities are considered to be public utility companies. Transportation and distribution of crude oil, natural gas and activities and are subject to governmental regulation. Article 58 of the refined products must comply with the Petroleum Code, the Commerce Code Petroleum Code establishes that oil refining activities can be developed (Código de Comercio) and with all governmental decrees and resolutions. throughout Colombia. Oil refineries must comply with the technical characteristics and requirements established by the existing regulations. Notwithstanding the general rules for hydrocarbon transportation in Colombia, natural gas transportation has specific regulations, due to the The Ministry of Mines and Energy is responsible for regulating, supervising and categorization of natural gas distribution as a public utility activity under overseeing all activities related to the refining of crude oil, import of refined Colombian laws. Therefore, natural gas distribution transportation is governed products, storage, transport and distribution. by specific regulation, issued by the CREG that seeks primarily to satisfy the Decree 2657 of 1964 regulated the oil refining activities and created the Oil Refining Planning Committee, which is responsible for studying industry The exportation of natural gas is not considered a public utility activity under problems and implementing short- and long-term refining planning policies. Colombian law and therefore is not subject to Law 142 of 1994. Nevertheless, The Committee is also responsible for evaluating and reviewing new refining the internal supply of natural gas is a priority for the Colombian government. projects or expansion of existing infrastructure. In evaluating a new project, This policy is included in Decree 2100 of 2011, providing that in the event the the Committee must take into account the significance of the project and the supply of natural gas is reduced or halted as a result of a shortage of this needs of the population. 110 GeoPark 20F hydrocarbon, the Colombian government has the right to suspend the supply Resolution 8 of the board of the Colombian Central Bank, or the Exchange of natural gas to foreign customers. Notwithstanding the foregoing, the Statute, and its amendments contain provisions governing exchange Decree 2100 of 2011, establishes freedom to export natural gas, under normal operations. Articles 48 to 52 of Resolution 8 provide for a special exchange conditions for gas reserves. regime for the oil industry that removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by Transport systems, classified as crude oil pipelines and multipurpose pipelines, can foreign oil companies. Such companies may not acquire foreign currency in be owned by private parties. The building, operation and maintenance of the exchange market under any circumstances and must reinstate in the pipelines must comply with environmental, social, technical and economic foreign exchange market the capital required in order to meet expenses in requirements under national and international standards. Transportation Colombian legal currency. Companies can avoid participating in this special oil networks must follow specific conditions regarding design and specifications, and gas exchange regime, however, by informing the Colombian Central Bank, while complying with the quality standards demanded by the oil and gas industry. in which case they will be subject to the general exchange regime of Resolution 8 and may not be able to access the special exchange regime for a According to Law 681 of 2001, multipurpose pipelines must be open to period of 10 years. third-party use and owners must offer their capacity on the basis of equal access to all. Hydrocarbon transport activity may be developed by third parties On December 26, 2012, Colombian Congress approved a number of tax and must meet all requirements established by law. reforms. These changes include, among other things, VAT rate consolidation, a reduction in corporate income tax (from 33% to 25%), changes to transfer The Ministry of Mines and Energy is responsible for studying and approving pricing rules, the creation of a new corporate income tax to pay for health, the design and blueprints of all pipelines, mediation of rates between parties education and family care issues (9% for fiscal years 2013 to 2015 and 8% from or, in case of disagreement, establishing the hydrocarbon transport rates 2016 and beyond), modifications in individual income tax, new “thin based on information furnished by the service provider, issuing hydrocarbon capitalization” rules and a reduction of social contributions paid by certain transport regulations, liquidation, distribution and verification of payment of employees. The implementation of such tax reforms requires further transport-related taxes and managing the information system for the oil administrative regulation. As of the date of this annual report, some product distribution chain. administrative regulations had been published, although we do not expect the final impact of these reforms to be material to our business. The construction of transportation systems requires government licenses and local permits awarded by the Ministry of Environment, in addition to other In December 2014, Colombian Congress approved a tax reform. This reform has requirements from the regional environmental authorities. introduced a temporary net wealth tax assessed on net equity on domestic and Further regulations on pipeline access and tariff systems have been defined by contribution on equality, “CREE” for its Spanish acronym) at 9%, and applied a the Ministry of Mines and Energy. Over the past months, the Ministry of Mines CREE surcharge until 2018, among other changes. The net wealth tax (NWT) and Energy has been working on a project to modify the 2010 regulation of assessed on net equity would apply for tax years 2015 through 2017 for foreign legal entities, kept the rate of the income tax on equality (enterprise pipeline access and tariff systems. Taxation domestic and foreign entities that hold any wealth in Colombia, directly or indirectly, via permanent establishments (PEs) or branches. In the case of foreign or domestic individuals, the NWT would apply until 2018. NWT will The Tax Statute and Law 9 of 1991 provide the primary features of the oil and apply, for corporate taxpayers ,at progressive rates ranging from 1.15% in 2014; gas industry’s tax and exchange system in Colombia. Generally, national taxes 1% in 2015 and decrease to 0.4% in 2016 and finally disappear in 2017,. NWT under the general tax statute apply to all taxpayers, regardless of industry. The paid would not be deductible or creditable for Colombian income tax purposes. main taxes currently in effect-after the December 2012 tax reform discussed The Reform also extended the current 9% CREE tax rate, which was scheduled below-are the income tax (25%), the special income tax for the development to decrease to 8% in 2016. Also, it will introduce a new CREE surcharge, of social investments (9% for 2013 to 2015 and 8% for 2016 and beyond) the beginning in 2015, from 5% in 2015, 6% in 2016, 8% in 2017 and 9% in 2018. equity or net assets tax, sales or value added tax (16%), and the tax on financial Therefore, the accumulated corporate income tax rate will rise to 43% in 2018. transaction (0.4%). Additional regional taxes also apply. Colombia has entered into a number of international tax treaties to avoid double taxation and Brazil prevent tax evasion in matters of income tax and net asset tax. Regulation of the oil and gas industry Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international Government’s monopoly over the prospecting and exploration of oil, natural investment regime, regulates foreign capital investment in Colombia. gas resources and other fluid hydrocarbon deposits, as well as over the refining, Article 177 of the Brazilian Federal Constitution of 1988 provides for the Federal GeoPark 111 importation, exportation and sea or pipeline transportation of crude oil and cost of oil imported for use in refineries to the price of refined oil products natural gas. Initially, paragraph one of article 177 barred the assignment or charged to the consumer. Under the rules adopted following the Brazilian concession of any kind of involvement in the exploration of oil or natural gas Petroleum Law, the Brazilian government changed its price regulation policies. deposits to private industry. On November 9, 1995, however, Constitutional Under these regulations, the Brazilian government: (1) introduced a new Amendment Number 9 altered paragraph one of article 177 so as to allow methodology for determining the price of oil products designed to track private or state-owned companies to engage in the exploration and production prevailing international prices denominated in U.S. dollars, and (2) gradually of oil and natural gas, subject to the conditions to be set forth by legislation. eliminated controls on wholesale prices. The Brazilian Petroleum Law, which enacted this constitutional provision: Concessions • confirmed the Federal Government’s monopoly over oil and natural gas In addition to opening the Brazilian oil and natural gas industry to private deposits and further provided that the exploration and production of such investment, the Brazilian Petroleum Law created new institutions, including the hydrocarbons would be regulated and overseen by the federal government; ANP, to regulate and control activities in the sector. As part of this mandate, the • created the CNPE (as defined below) and the ANP; ANP is responsible for licensing concession rights for the exploration, • revoked Law Number 2,004/53, which appointed Petrobras as the exclusive development and production of oil and natural gas in Brazil’s sedimentary basins agent to execute the Federal Government’s monopoly; and through a transparent and competitive bidding process. The ANP has conducted • established a transitional rule that entitled Petrobras to: (1) produce in fields 12 bidding rounds for exploration concessions since 1999. In November 2013, where Petrobras had already started production under a concession the twelfth round was conducted; 240 blocks in 13 sectors of seven basins were agreement made with the ANP for 27 years, on an exclusive basis, starting on offered, of which 72 were awarded. Of these 72 blocks, we were awarded two the date the field was declared commercially profitable; and (2) explore areas where Petrobras was able to show evidence of “established reserves” prior to the enactment of the Brazilian Petroleum Law, for up to three years, new concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of Maranhăo and the SEAL-T-268 Concession in the Sergipe Alagoas Basin in the State of Alagoas). Our PN-T-597 is still subject to the entry into the concession subsequently extended to five years. Regulatory entities National petroleum, natural gas and biofuel agency (ANP) agreement. See “-Our operations-Operations in Brazil” and “Item 3. Key information-D. Risk factors-Risks relating to our business-The PN-T-597 concession is subject to an injunction and may not close” for more information. The Brazilian Petroleum Law created the ANP. The ANP is a regulatory body of In order to participate in the auction process a company must have proven the federal government associated with the Ministry of Mines and Energy. The experience in oil and gas exploration and production activities, be legally ANP’s function is to regulate the oil, natural gas and biofuels industry in Brazil. constituted under the laws of their home country and undertake that, in the One of the ANP’s primary objectives is to create a competitive environment for event that they are successful in bidding, the company will constitute a oil and natural gas activities in Brazil that will lead to the lowest prices and company with its headquarters and management in Brazil, organized under best services for consumers. Its principal responsibilities include enforcing Brazilian law, and have the determined (specific for each bidding round) regulations as well as awarding concessions related to oil, natural gas and minimum net equity. If all requirements are met, the company will be considered biofuels, in accordance with the Brazilian Petroleum Law, as set forth in Decree qualified to bid and make offers for the bidding areas within its category. No. 2,455, dated January 14, 1998, and regulations enacted by the National Council on Energy Policy and National Interest. Environmental issues National council on energy policy (CNPE) The identification and definition of the concessions to be offered is based on the availability of geological and geophysical data indicating the presence of The CNPE, also created by the Brazilian Petroleum Law, is a council of the hydrocarbons. Also, in order to protect the environment, the ANP, the IBAMA President of Brazil presided over by the Minister of Mines and Energy. The and the state environmental agencies analyze all the areas prior to deciding CNPE is charged with submitting national energy policies, designing oil and which concessions to offer in licensing rounds. The requirement levels for natural gas production policies and establishing the procedural guidelines for environmental licensing for the various concessions to be auctioned are then competitive bids regarding the exploration concessions and areas with published, allowing the future concessionaire to include environmental established viability in accordance with the Brazilian Petroleum Law. considerations in determining what projects to pursue. These environmental guidelines are revised and updated with every ANP bidding round. Regulatory framework Pricing policy Consortium Until the enactment of the Brazilian Petroleum Law, the Brazilian government The oil and natural gas industry is characterized in Brazil by the presence of regulated all aspects of the pricing of oil and oil products in Brazil, from the several companies acting through consortium agreements, or unincorporated 112 GeoPark 20F joint ventures, in order to share the risks of exploration, development and respect to production. Royalties generally correspond to a percentage ranging production activities. Terms of those agreements are set out by the ANP and the actual risk sharing agreement is reflected in joint operating agreements. Taxation between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines ( edital de licitaçăo ) and concession agreement. In determining the percentage of royalties applicable to a particular concession, the ANP takes into consideration, among other Introduction. The Brazilian Petroleum Law introduced significant modifications factors, the geological risks involved and the production levels expected. and benefits to the taxation of oil and natural gas activities. The main component of petroleum taxation is the government take, comprised of license Relevant Tax Aspects on Upstream Activities. The special customs regime for fees, fees payable in connection with the occupation or title of areas, royalties goods to be used in the oil and gas activities in Brazil, REPETRO, aims primarily and a special participation fee. The introduction of the Brazilian Petroleum Law at reducing the tax burden on companies involved in exploring and extracting presents certain tax benefits primarily with respect to indirect taxes. Such oil and natural gas, through the total suspension of federal taxes due on the indirect taxes are very complex and can add significantly to project costs. Direct importation of equipment (platforms, subsea equipment, among others), taxes are mainly corporate income tax and social contribution on net profit. under leasing agreements, subject to the compliance with applicable legal Government take. With the effectiveness of the Brazilian Petroleum Law and under the REPETRO regime may vary depending on the importer, but usually the regulations promulgated by the ANP, concessionaires are required to pay corresponds to the duration of the contract executed between the Brazilian the Brazilian federal government the following: company and the foreign entity, or the period for which the company was requirements. The period in which the goods are allowed to remain in Brazil • license fees; • rent for the occupation or retention of areas; • special participation fee; and • royalties on production. authorized to exploit or produce oil and gas. In 2007, the legislation regarding the State Value Added Tax-ICMS imposed taxation on the import of equipment into Brazil under the REPETRO regime was significantly changed by ICMS Convention No. 130/2007. This regulation The minimum value of the license fees is established in the bidding rules for allows each State to grant the ICMS tax calculation basis reduction (generating the concessions, and the amount is based on the assessment of the potential, a tax burden of 7.5% with the recoverability of credits or 3%, without the as conducted by the ANP. The license fees must be paid upon the execution of recoverability of credits) for goods purchased under the REPETRO regime for the concession contract. Additionally, concessionaires are required to pay a the production phase and the total exemption or ICMS tax calculation basis rental fee to landowners varying from 0.5% to 1.0% of the respective reduction (generating a tax burden of 1.5%, without the recoverability of hydrocarbon production. credits) for the exploration phase. In order to be in force, the ICMS Convention No. 130/07 must be included in each state’s legislation. The special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or For example, currently, based on Convention No. 130/2007 , the state of Rio de profitability from oil fields, according to criteria established by applicable Janeiro grants tax calculation basis reduction for the exploitation (generating regulation, and is payable on a quarterly basis for each field from the date on a tax burden of 7.5%, with the recoverability of credits or 3%, without the which extraordinary production occurs. This participation rate, whenever due, recoverability of credits) and production of oil and gas (generating a tax may reach up to 40% of net revenues depending on (i) volume of production burden of 1.5%, without the recoverability of credits). For production activities, and (ii) whether the block is onshore, shallow water or deep water. Under the the legislation used to grant an exemption of ICMS, which was changed to a Brazilian Petroleum Law and applicable regulations issued by the ANP, the tax calculation basis reduction, according to Resolution Sefaz No. 631, dated special participation fee is calculated based upon quarterly net revenues of May 14th, 2013. each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate It is important to mention that before the enactment of the Convention No. for the period) less: • royalties paid; • investment in exploration; • operational costs; and 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on production activities, based on State Law No. 4,117, dated June, 27, 2003, which was regulated by Decree No. 34,761, dated February 3, 2004, and was subsequently suspended by Decree No. 34,783 of February 4, 2004 for an • depreciation adjustments and applicable taxes. undetermined period of time. Nevertheless, the State of Rio de Janeiro may choose to enforce the law at any time. Also, the constitutionality of this law The ANP is responsible for determining monthly minimum prices for is currently being challenged by the Public Ministry in the Supreme Court petroleum produced in concessions for purposes of royalties payable with (ADI 3,019-RJ). GeoPark 113 Pursuant to the Brazilian Petroleum Law and subsequent legislation, the federal divided into several periods as agreed in the contract, and all of them with a government enacted Law No. 10,336/01, to impose the Contribution for minimum work obligation that should be fulfilled by a contractor in order to Intervention in the Economic Sector, or CIDE, an excise tax payable by access to the next exploration period. The exploitation phase will last 40 years producers, blenders and importers on transactions with some of oil and fuel from the effective date of the contract in case of natural gas discoveries and 30 products, which is imposed at a flat amount based on the specific quantities of years from the effective date in case of oil discoveries. each product. Currently, the CIDE rates are zero, based on Decree No. 7,764/2012. Brazil has enacted a corporate tax reform, Law 12.973 of 13 May 2014. On three years for the exploration stage, if the contractor has fulfilled with the upstream operations, as from 2015 fiscal year, the new tax law may generate minimum work program established in the contract, and also commits to fulfill timing effects for income tax purposes on the deduction of pre-operational an additional work program that justifies such extension. The contractor shall costs as well as depreciation of fixed assets and amortization of intangibles. The be responsible for providing the technical and economic resources required new law imposes restrictions for the tax deduction of goodwill arising from for the execution of the operations of this phase. The Ministry of Energy and Mines may exceptionally authorize an extension of in-house operations, and brings several changes to the Brazilian CFC rules. Peru The Peruvian regulations also established the roles of the Peruvian government agencies that regulate, promote and supervise oil and gas industry, including Regulation of the oil and gas industry the Ministry of Energy and Mines, Perupetro and OSINERGMIN. The hydrocarbons activities in Peru are mainly regulated by the General Hydrocarbons Law (Law 26,221), and several regulations enacted in order to Taxation develop the provisions included in such law. The fiscal regime that applies in Peru to the oil and gas industry consists of a combination of corporate income tax, royalties and other levies. According to the Hydrocarbons Law, oil and gas exploration and production activities are carried out under license or service contracts granted by the In general terms, oil and gas companies are subject to the general corporate government. Under a license contract, the investor pays a royalty, whereas income tax regime; nevertheless, there are certain special tax provisions for the under a service contract, the government pays remuneration to the contractor. oil and gas sector. Resident companies (incorporated in Peru), are subject to As stated by the Peruvian Constitution and the Organic Law for Hydrocarbons, income tax on their worldwide taxable income. Branches and permanent a license contract does not imply a transfer or lease of property over the area establishments of foreign companies that are located in Peru and non-resident of exploration or exploitation. By virtue of the license contract, the contractor entities are taxed on income from Peruvian sources only. acquires the authorization to explore or to exploit hydrocarbons in a determined area, and Perupetro (the entity that holds the Peruvian state Taxable income is generally computed by reducing gross revenue by cost of interest) transfers the property right in the extracted hydrocarbons to the goods sold and all expenses necessary to produce the income or maintain the contractor, who must pay a royalty to the state. source of income. Certain types of revenue, however, must be computed as specified in the tax law and some expenses are not fully deductible for tax License and service contracts are approved by a supreme decree issued by the purposes. Business transactions must be recorded in legally authorized Peruvian Ministry of Economy and Finance, and the Peruvian Ministry of accounting records that are in full compliance with the International Energy and Mining, and can only be modified by a written agreement signed Accounting Standards (IAS). Contractors in a license or services contract for the by the parties. Before initiating any negotiation, every oil and gas company exploration or exploitation of hydrocarbons (Peruvian corporations and must be duly qualified by Perupetro, in order to determine if it fulfills all the branches) are entitled to keep their accounting records in foreign currency, requirements needed to develop exploration and production activities under but taxes must be paid in Peruvian Nuevos Soles (“PEN”). the contract form requirements mentioned above. When a contractor is a foreign investor, it is expected to incorporate a subsidiary company or Any investments in a contract area that did not reach the commercial registered branch in accordance with Peru’s laws and to appoint local extraction stage and that were totally released, can be accumulated with the representatives who will interact with Perupetro. same type of investments made in another contract that is in the process of commercial extraction. These investments are amortized in accordance with License and services agreements may be granted for just an exploitation stage the amortization method chosen in the letter contract. If the contractor has -when a commercial discovery has been made- or for an exploration and entered into a single contract, the accumulated investments are charged as a exploitation stage -when such discovery has not been made yet. In this case, loss against the results of the contract for the year of total release of the area the exploration phase will last no more than 7 years, counted from the for any contract that did not reach the commercial extraction stage, with the effective date of the contract (60 days after the signing date). This term can be exception of investments consisting of buildings, power installations, camps, 114 GeoPark 20F means of communication, equipment and other goods that the contractor (each one equal to one month of salary), c) severance payment (CTS), d) family keeps or recovers to use in the same operations or in other operations of a allowance, e) public health insurance, and f ) life insurance. different nature. The contractor determines the tax base and the amount of the tax, separately distribute a percentage of their annual income among their workers. The and for each contract. If the contractor carries out related activities (i.e., percentage to be distributed depends on the activity to be performed by the activities related to oil and gas, but not carried out under the terms of the company. In case of companies that perform oil and gas activities, the contract) or other activities (i.e., activities not related to oil and gas), the percentage will be 5%. In addition, companies that generate business income are required to contractor is obligated to determine the tax base and the amount of tax, separately, and for each activity. Employment contracts can only be terminated based on the reasons provided by Peruvian law. If an employment contract is terminated for any other reason, The corresponding tax is determined based on the income tax provisions that the employer will be required to pay damages to the employee for arbitrary apply in each case (subject to the tax stability provisions for contract activities dismissal (calculated according to the length of service), or may be required to and based on the regular regime for the related activities or other activities). reinstate the employee. The total income tax amount that the contractor must pay is the sum of the amounts calculated for each contract, for both the related activities and for the Foreign workers are allowed by Peruvian labor laws. However, such workers other activities. The forms to be used for tax statements and payments are should not exceed the 20% of the total workforce of the company, except by determined by the tax administration. If the contractor has more than one specialized technical staff or management staff for new business activities. Any contract, it may offset the tax losses generated by one or more contracts foreign worker will need a proper immigration visa work in Peru. against the profits resulting from other contracts or related activities. Moreover, the tax losses resulting from related activities may be offset against There are several regulations for protecting the safety and health of the the profits from one or more contracts. workers. Oil and gas companies are obliged to fulfil not only the general regime included in the labor laws, but also the specific regime approved for It is possible to choose the allocation of tax losses to one or more of the hydrocarbons activities. These regulations contain provisions on accident contracts or related activities that have generated the profits, provided that prevention, living conditions, sanitary facilities, water quality in the workplaces, the losses are depleted or are compensated to the limit of the profits available. medical assistance and first-aid services, safety measures related to camps, This means that if there is another contract or related activity, the taxpayer can medical assistance, food conditions, handling of explosives, etc. continue compensating tax losses until they are totally used. A contractor with tax losses from one or more contracts or related activities may not offset them Environmental Regulation. against profits generated by the other activities. Furthermore, in no case may Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling of tax losses generated by the other activities be offset against the profits exploration wells, etc.) the contractor must file and obtain an approval for an resulting from the contracts or from the related activities. Environmental Impact Study (EIS), which is the most important permit related to HSE for any hydrocarbon project. This study includes technical, During the exploration phase, operators are exempt from import duties and environmental and social evaluations of the project to be executed in order to other forms of taxation applicable to goods intended for exploration activities. define the activities that should be required for preventing, minimizing, Exemptions are withdrawn at the production phase, but exceptions are made mitigating and remediation of the possible negative environmental and social in certain instances, and the operator may be entitled to temporarily import impacts that the hydrocarbon project may generate. goods tax-free for a two-year period (“Temporary Import”). A temporary Import may be extended for additional one year periods for up to two years Depending on the type of hydrocarbon activity the contractor is intended to upon the request of an operator, approval of the Ministry of Energy and Mines execute, it should file the following types of environmental studies: and authorization of the Superintendencia Nacional de Aduanas y de • Environmental Impact Statement (EIS) Administracion Tributaria (Peruvian Customs Agency). • Environmental Impact Study (EIS) • Semi detailed Environmental Impact Study (SEIS) Labor and Safety Legislation. Indefinite-term contracts are the general rule for hiring in Peru, although The competent authority for approving the environmental studies is the fixed-term contracts and part-time contracts may also be signed as an Ministry of Energy and Mines, through the General Bureau of Energetic exception. In any labor contract in Peru, the workers will usually have, among Environmental Affairs (GBEEA). However, such role will be assumed by the others, the following labor benefits: a) vacation time, b) two legal bonuses Ministry of Environment in the short term. GeoPark 115 There are general environmental regulations for the protection of water, soils, air, as well as in the exploitation, industrialization, transportation and sale of endangered species, biodiversity, natural protected areas, etc. In addition, there hydrocarbons, a national public interest and a priority for Argentina. In are specific environmental regulations applicable to the hydrocarbon industry. addition, the law expropriated 51% of the share capital of YPF, the largest Argentine oil company, from Repsol, the largest Spanish oil company. Argentina Regulation of the oil and gas industry On July 28, 2012, Presidential Decree 1277/2012, which regulated the Under Argentine law, the federal executive branch establishes the federal Hydrocarbon Sovereignty Law, was released, establishing that the Strategic policy applicable to the exploration, exploitation, refining, transportation and Planning and Coordination Committee for the National Hydrocarbon marketing of liquid hydrocarbons, but the licensing and enforcement of Investment Plan must be in charge of the sector’s reference prices. The decree exploration and production activities has been transferred from the federal introduced important changes to the rules governing Argentina’s oil and gas government to provincial governments. Regulatory entities industry. The decree repeals certain articles of Deregulation Decrees passed during 1989 relating to free marketability of hydrocarbons at negotiated prices, the deregulation of the oil and gas industry, freedom to import and The principal authorities that regulate the activities in Argentina are the export hydrocarbons and the ability to keep proceeds from export sales in Secretariat of Energy and the Strategic Planning and Coordination Committee foreign bank accounts. The repeal of these articles appears to formalize certain for the National Hydrocarbon Investment Plan, at the federal level, and a local rules such as price controls and the repatriation of export sales proceeds, enforcement authority at each province (typically a secretariat of energy or which has been in fact required by the government over the last several years. hydrocarbons board). Regulatory framework In addition, the decree created the Strategic Planning and Coordination Committee for the National Hydrocarbon Investment Plan, charged with From the 1920s to 1989, the Argentine public sector dominated the upstream developing investment plans for the country to increase production and segment of the Argentine oil and gas industry and the midstream and reserves and to make Argentina more energy self-sufficient. The decree also downstream segment of the business. requires oil and gas companies, refiners and transporters of hydrocarbon products to submit annual investment plans for approval by the commission. In 1989, Argentina enacted certain laws aimed at privatizing the majority of its The decree empowers the commission to issue fines and sanctions, including state-owned companies and issued a series of presidential decrees (namely, concession termination, for companies that do not comply with its Decrees No. 1055/89, 1212/89 and 1589/89 (“Oil Deregulation Decrees”), relating requirements. Finally, the Strategic Planning and Coordination Committee for specifically to deregulation of energy activities). The Oil Deregulation Decrees the National Hydrocarbon Investment Plan is also charged with the eliminated restrictions on imports and exports of crude oil, deregulated the responsibility of assuring the reasonableness of hydrocarbon prices in the domestic oil industry, and effective January 1, 1991, the prices of oil and domestic market and that such prices allow companies to generate a petroleum products were also deregulated. In 1992, Law No. 24,145, referred to reasonable profit margin. as the Privatization Law, privatized YPF and provided for transfer of hydrocarbon reservoirs from the Argentine government to the provinces, subject to the Domain and Jurisdiction of hydrocarbons resources existing rights of the holders of exploration permits and production concessions. After a constitutional reform enacted in 1994, eminent domain over hydrocarbon resources lying in the territory of a provincial state is now vested In October 2004, the Argentine Congress enacted Law No. 25,943, creating a in such provincial state, while eminent domain over hydrocarbon resources new state-owned energy company, Energía Argentina S.A. (“ENARSA”). The lying offshore on the continental platform beyond the jurisdiction of the corporate purpose of ENARSA is the exploration and exploitation of solid, coastal provincial states is vested in the federal state liquid and gaseous hydrocarbons; the transport, storage, distribution, commercialization and industrialization of these products; as well as the Thus, oil and gas exploration permits and exploitation concessions are now transportation and distribution of natural gas, and the generation, granted by each provincial government. A majority of the existing concessions transportation, distribution and sale of electricity. Moreover, Law No. 25,943 were granted by the federal government prior to the enactment of Law No. granted ENARSA all offshore areas located beyond 12 nautical miles from the 26,197 and were thereafter transferred to the provincial states. coastline up to the outer boundary of the continental shelf that were vacant at the time of the effectiveness of this law ( i.e. , November 3, 2004). Regulation of exploration and production activities On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty In October 31, 2014 the Argentine Republic Official Gazette published the text Act. This law declared achieving self-sufficiency in the supply of hydrocarbons, of Law No. 27,007, amending the Hydrocarbon Law No. 17,319. New Hydrocarbon Act: 116 GeoPark 20F Operating and financial review and prospects The most relevant aspects of the new law are as follows: hydrocarbons on an open-access basis, for a fee which is the same for all users • With regards to concessions, three types of concessions are provided, namely, on similar terms. As a result of the privatizations of YPF and Gas del Estado, a conventional exploitation, unconventional exploitation, and exploitation in few common carriers of crude oil and natural gas were chartered and continue the continental shelf and territorial waters, establishing the respective terms to operate to date. for each type. • The terms for hydrocarbon transportation concessions were adjusted in Taxation order to comply with the exploitation concessions terms. Exploitation concessionaires are subject to the general federal and provincial • With regards to royalties, a maximum of 12% is established, which may reach tax regime. The most relevant federal taxes are the income tax (35%), the value 18% in the case of granted extensions, where the law also establishes the added tax (21%) and a tax on assets. The most relevant provincial taxes are the payment of an extension bond for a maximum amount equal to the amount turnover tax (1% to 3%) and stamp tax. In 2002, in response to the economic resulting from multiplying the remaining proven reserves at the end of crisis, the federal government adopted new taxes on oil and gas products, effective term of the concession by 2% of the average basin price applicable including export taxes ranging from 5% for by-products to 45% for crude oil. to the respective hydrocarbons over the 2 years preceding the time on which Despite that, under certain incentives programs established in 2008 (namely, the extension was granted. the Oil Plus Program and the Refining Plus Program created by Presidential • The extension of the Investment Promotion Regime for the Exploitation of Decree 2014/2008), oil and gas companies increasing their oil reserves and Hydrocarbons (Decree No. 929/2013) is established for projects representing production and refining companies increasing their production would be a direct investment in foreign currency of at least 250 million dollars, granted tax rebate certificates to be credited against the payment of the increasing the benefits for other type of projects. export taxes. However, the Oil Plus Program and the Refining Plus Program were suspended for certain companies in February 2012 and subsequently Regulation of refining and petrochemical activities amended and reinstated in June 2012. Refining and petrochemical activities in Argentina have historically been governed by free enterprise and private refineries have coexisted with C. Organizational structure state-owned refineries. We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of Until 1989, crude oil production, whether extracted by YPF or by private subsidiaries. See an illustration of our corporate structure in Note 20 companies operating under service contracts, was delivered to YPF, and the (“Subsidiary undertakings”) to our Consolidated Financial Statements. Secretariat of Energy distributed the same among the refining companies according to quotas. Natural gas production was until then also delivered to D. Property, plant and equipment YPF and to the then existing state-owned Gas del Estado SE utility company. See “-B. Business Overview-Title to properties” The Oil Deregulation Decrees issued in 1989 deregulated the hydrocarbons industry and granted to the holders of hydrocarbon permits and concessions ITEM 4A. UNRESOLVED STAFF COMMENTS the right to freely dispose of the hydrocarbons lifted by them at free market Not applicable. conditions, and abrogated the previous quota allocation system. After the economic crisis of 2001 and 2002, hydrocarbons refiners and ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS producers were prompted by the Argentine government to enter into a series of tripartite agreements whereby the prices of crude oil and certain A. Operating results byproducts were capped or regulated. A series of other measures was also The following discussion of our financial condition and results of operations adopted, affecting the downstream segment of the industry. should be read in conjunction with our Consolidated Financial Statements and the notes thereto as well as the information presented under “Item 3. Key Information- Regulation of transportation activities A. Selected financial data.” Exploitation concessionaires have the exclusive right to obtain a transportation concession for the transport of oil and gas from the provincial The following discussion contains forward-looking statements that involve states or the federal government, depending on the applicable jurisdiction. risks and uncertainties. Our actual results may differ materially from those Such transportation concessions include storage, ports, pipelines and other discussed in the forward-looking statements as a result of various factors, fixed facilities necessary for the transportation of oil, gas and by-products. including those set forth in “Item 3. Key Information-D. Risk factors” and Transportation facilities with surplus capacity must transport third parties’ “Forward-looking statements.” GeoPark 117 Factors affecting our results of operations offtake and prepayment agreement signed on December 18, 2015 with We describe below the year-to-year comparisons of our historical results and Trafigura, a leading commodity trading and logistics company. If we are not the analysis of our financial condition. Our future results could differ materially able to generate the sales which, together with our current cash resources, are from our historical results due to a variety of factors, including the following: sufficient to fund our capital program, we will not be able to efficiently execute Discovery and exploitation of reserves program, which could harm our business outlook, investor confidence and our our work program which would cause us to further decrease our work Our results of operations depend on our level of success in finding, acquiring share price. (including through bidding rounds) or gaining access to oil and natural gas reserves. While we have geological reports evaluating certain proved, If oil prices average higher than the base budget price, we have the ability to contingent and prospective resources in our blocks, there is no assurance that allocate additional capital to more projects and increase its work and we will continue to be successful in the exploration, appraisal, development investment program and thereby further increase oil and gas production. and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is Our results of operations will be adversely affected in the event that our possible that our future exploration will not result in additional discoveries, estimated oil and natural gas asset base does not result in additional reserves and, even if we are able to successfully make such discoveries, there is no that may eventually be commercially developed. In addition, there can be no certainty that the discoveries will be commercially viable to produce. We have assurance that we will acquire new exploration blocks or gain access to been able to successfully develop our assets through drilling, with 72%, or 151, exploration blocks that contain reserves. Unless we succeed in exploration and of the 211 exploratory, appraisal and development wells that we drilled from development activities, or acquire properties that contain new reserves, our January 1, 2006 through December 31, 2015 becoming productive wells. anticipated reserves will continually decrease, which would have a material For the year ended December 31, 2015, we made total capital expenditures of US$48.8 million (US$30.7 million, US$12.4 million, US$0.1 million and US$5.6 Oil and gas revenue and international prices million in Colombia, Chile, Argentina and Brazil, respectively) for the year 2015, Our revenues are derived from the sale of our oil and natural gas production, consisting of US$12.3 million related to exploration. as well as of condensate derived from the production of natural gas. Our oil adverse effect on our business, results of operations and financial condition. and natural gas prices are driven by the international prices of oil and Oil prices were volatile since the end of 2014 and have remained at low levels methanol (for our Chilean gas production), respectively, which are in the first part of 2016. In preparation for continued volatility, we developed denominated in US$. The price realized for the oil we produce is linked to WTI multiple scenarios for our 2016 capital expenditure program, as follows: and Brent, US$ denominated international benchmarks. The price realized for Our preliminary base capital program for 2016 calls for approximately US$45 methanol, which is settled in the international markets in US$. The market million-US$55 million to fund our exploration and development, which we price of these commodities is subject to significant fluctuation and has intend to fund through cash flows from operations and cash-in-hand. In historically fluctuated widely in response to relatively minor changes in the addition, we have developed downside and upside work program scenarios global supply and demand for oil and natural gas, market uncertainty, based on different oil prices and project performance. The downside scenario economic conditions and a variety of additional factors. the natural gas we produce in Chile is linked to the international price of work program consists of an alternative capital expenditure program of approximately US$20 million-US$25 million consisting mainly of certain low From January 1, 2010 to December 31, 2015, Brent spot prices ranged from a risk and quick cash flow generating projects. The upside scenario work low of US$35.26 per barrel to a high of US$128.14 per barrel, NYMEX West program consists of an alternative capital expenditure program of Texas International (“WTI”) crude oil contracts prices ranged from a low of approximately US$75 million-US$90 million to be selected from identified US$34.55 per bbl to a high of US$113.39 per bbl, Henry Hub natural gas projects designed to increase reserves and production. average spot prices ranged from a low of US$1.63 per mmbtu to a high of Funding for these programs relies in part on oil prices remaining close to our US$330.47 per metric ton to a high of US$634.23 per metric ton. We have estimates or higher levels and other factors to generate sufficient cash flow. historically not hedged our production to protect against fluctuations in the US$8.63 per mmbtu, US Gulf methanol spot barge prices ranged from a low of Low oil prices affect our revenues, which in turn affect our debt capacity and international oil prices. the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able As a consequence of the oil price crisis which started in the second half of to generate from current operations and the amount of cash we can obtain 2014 (WTI and Brent, the main international oil price markers, fell more than from prepayment agreements such as the Trafigura Agreement, which is our 60% between August 2014 and March 2016), we have undertaken a decisive 118 GeoPark 20F cost cutting program to ensure our ability to both maximize the work program In Brazil, prices for gas produced in the Manati Field are based on a long-term and preserve our cash. off-take contract with Petrobras. For the year ended December 31, 2015, Rio das Contas’s average sale price was US$28/boe. The price of gas sold under this During 2015, we took decisive steps to adapt to the new oil price environment. contract is denominated in reais and is adjusted annually for inflation We reduced our 2015 capital expenditure program by 79% year-over-year and pursuant to the Brazilian General Market Price Index ( Índice Geral de implemented significant cost reduction initiatives that resulted in production Preços-Mercado ) (“IGPM”). and operating costs being reduced by 34%, drilling costs being reduced by approximately 25%, and administrative and selling expenses being reduced by We do not have a price-hedging transaction currently outstanding. Our Board 39%, while achieving an average production of 20,367 boepd and increasing of Directors could consider adopting commodity price hedging measures, our proved reserves to 48.6 mmboe. For more information see “Item 3. Key when deemed appropriate, according to the size of the business, production Information-D. Risk Factors-Risks relating to our business-The current oil price levels and market volatility. crisis has impacted on our operations and corporate strategy.” Production and operating costs Additionally, the oil and gas we sell may be subject to certain discounts. For Our production and operating costs consist primarily of expenses associated instance, in Chile, the price of oil we sell to ENAP is based on Brent minus with the production of oil and gas, the most significant of which are gas plant certain marketing and quality discounts. As a result, our average realized price leasing, facilities and wells maintenance (including pulling works), labor costs, for the years ended December 31, 2015 and 2014 was of US$42.2 per bbl and contractor and consultant fees, chemical analysis, royalties and products, US$89.4 per bbl, respectively. among others. As commodity prices increase or decrease, our production costs may vary. We have historically not hedged our costs to protect against We have a long-term gas supply contract with Methanex. The price of the gas fluctuations. sold under this contract is determined based on a formula that takes into account various international prices of methanol, including US Gulf methanol Availability and reliability of infrastructure spot barge prices, methanol spot Rotterdam prices and spot prices in Asia. See Our business depends on the availability and reliability of operating and “Item 3. Key Information-D. Risk factors-Risks relating to our business-A transportation infrastructure in the areas in which we operate. Prices and substantial or extended decline in oil, natural gas and methanol prices may availability for equipment and infrastructure, and the maintenance thereof, materially adversely affect our business, financial condition or results of affect our ability to make the investments necessary to operate our business, operations.” As of the date of this annual report, we had not entered into any and thus our results of operations and financial condition. See “Item 3. Key derivative arrangements or contracts to mitigate the impact on our results of Information-D. Risk factors-Risks relating to our business-Our inability to access operations of fluctuations in commodity prices. needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental In Colombia, the price of oil we sell is based on Vasconia, a marker broadly costs or delays in our oil and natural gas production.” used in the Llanos Basin, adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulfur, delivery point and water In order to mitigate the risk of unavailability of operating and transportation content, as well as on certain transportation costs (including pipeline costs infrastructure, we have invested in the construction of plant and pipeline and trucking costs). The delivery points for our production range from the well infrastructure to produce, process and store hydrocarbon reserves and to head to the port of export (Coveñas), depend on the client: if sales are made transport them to market. In the Fell Block, for example, we have constructed via pipeline, the delivery point is usually the pipeline injection point, whereas over 120 km of pipeline and a gas plant with a processing and compression for direct export sales, the most frequent delivery point is the well head. As a capacity of 35.3 mmcfpd. We also constructed an oil treatment plant with a result, our average realized price for the years ended December 31, 2015 and processing capacity of 9,500 bopd to service oil produced in the Fell Block, 2014 was of US$28.8 per bbl and US$73.0 per bbl, respectively. Our oil sales which became operative in November 2013. contracts in Colombia are short-term agreements and do not commit the parties to a minimum volume, and are subject to the ability of either party to Production levels receive or deliver the production, as applicable. Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and, to a lesser extent, oil and natural gas prices. Since being If the market prices of oil and methanol had fallen by 10% as compared to awarded 100% of the working interest in the Fell Block in 2006, and through actual prices during the year, with all other variables held constant, after-tax December 31, 2015, we have drilled 113 exploratory, appraisal and loss for the year ended December 31, 2015 would have been higher by US$23.9 development wells in the Fell Block, with 76%, or 86, of such wells becoming million (after-tax profit would have been US$29.2 million lower in 2014). productive. Production at the Fell Block has increased from approximately GeoPark 119 1,400 boepd in 2007 to 3,834 boepd as of December 31, 2015. Since acquiring Acquisitions our Colombian operations and through December 31, 2015, 73 exploratory, Our results of operations are significantly affected by our past acquisitions. We appraisal and development wells have been drilled in blocks in which we have generally incorporate our acquired business into our results of operations at or working interests and/or economic interests, with 68% of such wells becoming around the date of closing, such as our Colombian acquisitions in 2012 and productive. Production in our Colombian operations has increased from 2,965 our Rio das Contas acquisition in 2014, which limits the comparability of the boepd for the month of April 30, 2012 to 13,183 boepd for the year ended period including such acquisitions with prior or future periods. December 31, 2015. We expect that fluctuations in our financial condition and results of operations in Latin America. We intend to continue to selectively acquire companies, will be driven by the rate at which production volumes from our wells decline. producing properties and concessions, as the pending Morona Block. As with As initial reservoir pressures are depleted, oil and gas production from a given our historical acquisitions, any future acquisitions could make year-to-year well will decline over time. See “Item 3. Key Information-D. Risk factors-Risks comparisons of our results of operations difficult. We may also incur relating to our business-Unless we replace our oil and natural gas reserves, our additional debt, issue equity securities or use other funding sources to fund As described above, part of our strategy is to acquire and consolidate assets reserves and production will decline over time. Our business is dependent on future acquisitions. our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or Functional and presentational currency natural gas in commercial quantities.” Contractual obligations Our Consolidated Financial Statements are presented in US$, which is our functional and presentational currency. Items included in the financial information of each of our entities are measured using the currency of the In order to protect our exploration and production rights in our license areas, primary economic environment in which the entity operates, or the functional we must make and declare discoveries within certain time periods specified in currency, which is the US$ in each case, except for our Brazil operations, where our various special contracts, E&P Contracts and concession agreements. The the functional currency is the real . costs to maintain or operate our license areas may fluctuate or increase significantly, and we may not be able to meet our commitments under these Geographical segment reporting agreements on commercially reasonable terms or at all, which may force us to In the description of our results of operations that follow, our “Other” operations forfeit our interests in such areas. If we do not succeed in renewing these reflect our non-Chilean, non-Colombian and non-Brazilian operations, primarily agreements, or in securing new ones, our ability to grow our business may be consisting of our Argentine, Peruvian (mainly related to the start-up of our materially impaired. See “Item 3. Key Information-D. Risk factors-Risks relating operations in such country) and corporate head office operations. to our business-Under the terms of some of our various CEOPs, E&P Contracts and concession agreements, we are obligated to drill wells, declare any We divide our business into five geographical segments-Colombia, Chile, discoveries and file periodic reports in order to retain our rights and establish Brazil, Peru and Argentina-that correspond to our principal jurisdictions of development areas. Failure to meet these obligations may result in the loss of operation. Activities not falling into these four geographical segments are our interests in the undeveloped parts of our blocks or concession areas.” reported under a separate corporate segment that primarily includes certain Administrative expenses corporate administrative costs not attributable to another segment. As of December 31, 2015, our Chilean segment contributed US$44.8 million, or Our administrative expenses for the year ended December 31, 2015 decreased 21.4%, of our revenues, our Colombian segment contributed US$131.9 by US$8.4 million, or (18.3)%, compared to the year ended December 31, 2014 million, or 62.9%, of our revenues, our Brazilian segment contributed US$32.4 resulting from financial discipline and cost reduction initiatives. Our million, or 15.4%, of our revenues and our Argentine segment contributed administrative expenses increased by US$0.9 million, or 2.0%, from 2013 to US$0.6 million, or 0.3%, of our revenues. 2014, mainly due to (i) higher corporate expenses related to our growth strategy and new business efforts, (2) incorporation of our Rio das Contas Description of principal line items operations in Brazil, and (iii) the start-up of our operations in Tierra del Fuego, The following is a brief description of the principal line items of our statement Chile, partially offset by lower administrative expenses in Colombia. of income. Furthermore, administrative costs may increase as a result of our Peruvian operations, and as a result of becoming a publicly traded company in the Net revenue United States. Public company costs include expenses associated with our Net revenue includes the sale of crude oil, condensate and natural gas net of annual and quarterly reporting, investor relations, registrar and transfer agent value-added tax (“VAT”), and discounts related to the sale (such as API and fees, incremental insurance costs and accounting and legal services. mercury adjustments) and overriding royalties due to the ex-owners of oil and 120 GeoPark 20F gas properties where the royalty arrangements represent a retained working Impairment of non-financial assets interest in the property. Revenue is recognized when the significant risks and Assets that are not subject to depreciation and/or amortization (such as rewards of ownership have been transferred to the buyer, the associated costs exploration and evaluation assets) are tested annually for impairment. Assets and amount of revenue can be estimated reliably, recovery of the that are subject to depreciation and/or amortization are reviewed for consideration is probable, and there is no continuing management impairment whenever events or changes in circumstances indicate that the involvement with the goods. carrying amount may not be recoverable. Production and operating costs An impairment loss is recognized for the amount by which the asset’s carrying For a description of our production and operating costs, see “-Factors affecting amount exceeds its recoverable amount. The recoverable amount is the higher our results of operations.” of an asset’s fair value minus costs to sell and value in use. Depreciation and write-off of unsuccessful efforts During 2015 and 2014 we recognized impairment losses amounting to Capitalized costs of proved oil and natural gas properties are depreciated on a US$149.6 million and US$9.4 million. No impairment loss was recognized in licensed-area-by-licensed-area basis, using the unit of production method, 2013. See Note 36 to our Consolidated Financial Statements. based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Financial costs Society of Petroleum Engineers and the World Petroleum Council (“PRMS”), Financial costs consist of financial income offset by financial expenses. which differs from SEC reporting guidelines pursuant to which certain Financial income includes interest received from bank time deposits. Financial information in the forepart of this annual report is presented. The calculation expenses principally include interest expense not subject to capitalization, of the “unit of production” depreciation takes into account estimated future bank charges and the unwinding of long-term liabilities. discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the Foreign exchange loss basis of approximate relative energy content. Foreign exchange loss represents the effect of exchange rate differences. In particular, upon completion of the evaluation phase, a prospect is either Loss or profit for the period attributable to owners of the Company transferred to oil and gas properties if it contains reserves, or is charged to Loss or profit for the period attributable to owners of the Company consists of profit and loss in the period in which the determination is made. See “-Critical losses or profit for the year less non-controlling interest. accounting policies and estimates-Oil and gas accounting.” Critical accounting policies and estimates In 2015, a charge of US$30.1 million has been recognized in the Consolidated We prepare our Consolidated Financial Statements in accordance with IFRS Statement of Income (US$30.4 million in 2014 and US$11.0 million in 2013) and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as for write-offs. The write-offs are detailed in Note 19 to our Consolidated adopted by the IASB. The preparation of the financial statements requires us to Financial Statements. Geological and geophysical expenses make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate these estimates and assumptions Geological and geophysical expenses consist of geosciences costs, including based on the most recently available information, our own historical wages and salaries and share-based compensation not subject to experience and various other assumptions that we believe to be reasonable capitalization, geological consultancy costs and costs relating to independent under the circumstances. Since the use of estimates is an integral component reservoir engineer studies. Administrative expenses of the financial reporting process, actual results could differ from those estimates. Administrative costs consist of corporate costs such as director fees and travel An accounting policy is considered critical if it requires an accounting estimate expenses, new project evaluations and back-office expenses principally to be made based on assumptions about matters that are highly uncertain at comprised of wages and salaries, share-based compensation, consultant fees the time such estimate is made, and if different accounting estimates that and other administrative costs, including certain costs relating to acquisitions. reasonably could have been used, or changes in the accounting estimates that Selling expenses are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following accounting policies represent critical Selling expenses consist primarily of transportation and storage costs. accounting policies as they involve a higher degree of judgment and GeoPark 121 complexity in their application and require us to make significant accounting Our management believes these factors and assumptions are reasonable estimates. The following descriptions of critical accounting policies and based on the information available at the time we prepare our estimates. estimates should be read in conjunction with our Consolidated Financial However, these estimates may change substantially as additional data from Statements and the accompanying notes and other disclosures. ongoing development activities and production performance becomes available and as economic conditions impacting oil and natural gas prices and Business combinations costs change. Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair market value of the assets For further information related to impairment of property, plant and acquired, equity instruments issued and liabilities incurred or assumed on the equipment, please see Note 36 to our Consolidated Financial Statements. date of completion of the acquisition. Acquisition costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and Oil and gas accounting liabilities and contingent liabilities assumed in a business combination are Oil and gas exploration and production activities are accounted for in measured initially at their fair market values at the acquisition date. The excess accordance with the successful efforts method on a field by field basis. We of the cost of acquisitions over fair market value of a company’s share of the account for exploration and evaluation activities in accordance with IFRS 6, identifiable net assets acquired is recorded as goodwill. If the cost of the Exploration for and Evaluation of Mineral Resources, capitalizing exploration acquisition is less than a company’s share of the net assets required, the and evaluation costs until such time as the economic viability of producing difference is recognized directly in the statement of income. the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the income statement. The determination of fair value of identifiable acquired assets and assumed liabilities means that we are to make estimates and use valuation techniques, Exploration and evaluation costs may include: license acquisition, geological including independent appraisers. The valuation assumptions underlying each and geophysical studies (i.e., seismic), direct labor costs and drilling costs of of these valuation methods are based on available updated information, exploratory wells. No depreciation and/or amortization are charged during the including discount rates, estimated cash flows, market risk rates and other exploration and evaluation phase. Upon completion of the evaluation phase, data. As a result, the process of identification and the related determination of the prospects are either transferred to oil and gas properties or charged to fair values require complex judgments and significant estimates. expense in the period in which the determination is made, depending whether they have found reserves. If not developed, exploration and Cash flow estimates for impairment assessments evaluation assets are written off after three years, unless it can be clearly Cash flow estimates for impairment assessments require assumptions about demonstrated that the carrying value of the investment is recoverable. All field two primary elements: future prices and reserves. Estimates of future prices development costs are considered construction in progress until they are require significant judgments about highly uncertain future events. finished and capitalized within oil and gas properties, and are subject to Historically, oil and natural gas prices have exhibited significant volatility. Our depreciation once completed. Such costs may include the acquisition and forecasts for oil and natural gas revenues are based on prices derived from installation of production facilities, development drilling costs (including dry future price forecasts among industry analysts, as well as our own assessments. holes, service wells and seismic surveys for development purposes), project- Estimates of future cash flows are generally based on assumptions of related engineering and the acquisition costs of rights and concessions related long-term prices and operating and development costs. to proved properties. The process of estimating reserves requires significant judgments and decisions Workovers of wells made to develop reserves and/or increase production are based on available geological, geophysical, engineering and economic data. The capitalized as development costs. Maintenance costs are charged to income estimation of economically recoverable oil and natural gas reserves and related when incurred. future net cash flows was performed based on the D&M Reserves Report. Such estimates incorporate many factors and assumptions including: Capitalized costs of proved oil and gas properties and production facilities and • expected reservoir characteristics based on geological, geophysical and machinery are depreciated on a licensed area by licensed area basis, using the engineering assessments; unit of production method, based on commercial proved and probable • future production rates based on historical performance and expected future reserves. The calculation of the “unit of production” depreciation takes into operating and investment activities; account estimated future finding and development costs, and is based on • future oil and natural gas prices and quality differentials; current year-end un-escalated price levels. Changes in reserves and cost • anticipated effects of regulation by governmental agencies; and estimates are recognized prospectively. Reserves are converted to equivalent • future development and operating costs. units on the basis of approximate relative energy content. 122 GeoPark 20F Oil and gas reserves for purposes of our Consolidated Financial Statements are Non-market vesting conditions are included in assumptions in respect of the determined in accordance with PRMS, and were estimated by D&M, number of options that are expected to vest. At each balance sheet date, we independent reserves engineers. 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 Depreciation of the remaining property, plant and equipment assets (i.e., statement of income, with a corresponding adjustment to equity. furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight line method by applying such annual The fair value of the share awards payments is determined at the grant date by rates as required to write-off their value at the end of their estimated useful reference of the market value of the shares and recognized as an expense over lives. The useful lives range between three and 10 years. the vesting period. Asset retirement obligations When options are exercised, we issue new common shares. The proceeds Obligations related to the plugging and abandonment of wells once operations received net of any directly attributable transaction costs are credited to share are terminated may result in the recognition of significant liabilities. We record capital (nominal value) and share premium when the options are exercised. the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recognized, the cost is Taxation also capitalized by increasing the carrying amount of the related asset. Over The computation of our income tax expense involves the interpretation of time, the liability is accreted to its present value at each reporting date, and the applicable tax laws and regulations in many jurisdictions. The resolution of tax capitalized cost is depreciated over the estimated useful life of the related asset. positions taken by us, through negotiations with relevant tax authorities or Estimating the future abandonment costs is difficult and requires management through litigation, can take several years to complete and in some cases it is to make assumptions and judgments because most of the obligations will be difficult to predict the ultimate outcome. settled after many years. Technologies and costs are constantly changing, as are political, environmental, health, safety and public relations considerations. In addition, we have tax-loss carry-forwards in certain taxing jurisdictions that Consequently, the timing and future cost of dismantling and abandonment are are available to offset against future taxable profit. However, deferred tax subject to significant modification. Any change in the variables underlying our assets are recognized only to the extent that it is probable that taxable profit assumptions and estimates can have a significant effect on the liability and the will be available against which the unused tax losses can be utilized. related capitalized asset and future charges related to the retirement Management judgment is exercised in assessing whether this is the case. obligations. The present value of future costs necessary for well plugging and abandonment is calculated for each area on the basis of cash flows discounted To the extent that actual outcomes differ from management’s estimates, at an average interest rate applicable to our indebtedness. The liability taxation charges or credits may arise in future periods. recognized is based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. Contingencies Share-based payments From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, We provide several equity-settled, share-based compensation plans to certain commercial, environmental and health & safety matters. For example, from time employees and third-party contractors, composed of payments in the form of to time, the Company receives notices of environmental, health and safety share awards and stock options plans. violations. Based on what our Management currently knows, such claims are not expected to have a material impact on the financial statements. Fair value of the stock option plans for employee or contractor services received in exchange for the grant of the options is recognized as an expense. The total Recent accounting pronouncements amount to be expensed over the vesting period, which is the period over which See note 2.1.1 to our Consolidated Financial Statements. all specified vesting conditions are to be satisfied, is determined by reference to the fair value of the options granted calculated using the Black-Scholes model. Results of operations Determining the total value of our share-based payments requires the use of The following discussion is of certain financial and operating data for the highly subjective assumptions, including the expected life of the stock options, periods indicated. You should read this discussion in conjunction with our estimated forfeitures and the price volatility of the underlying shares. The Consolidated Financial Statements and the accompanying notes. assumptions used in calculating the fair value of share-based payment represent management’s best estimates, but these estimates involve inherent We closed the acquisition of Brazilian Rio das Contas on March 31, 2014 and uncertainties and the application of management’s judgment. began consolidating its financials beginning on March 31, 2014. Accordingly, GeoPark 123 our results of operations for the year ended December 31, 2014, are not fully comparable with prior periods. See Note 34 to our Consolidated Financial Statements. For the year ended % Change December 31, from 2015 2014 prior year (in thousands of US$, except for percentages) As a consequence of the oil price crisis which started in the second half of Revenue 2014 (WTI and Brent, the main international oil price markers, fell more than Net oil sales 60% between August 2014 and March 2016), we have undertaken a decisive Net gas sales cost cutting program to ensure our ability to both maximize the work program Net revenue and preserve our cash. Production and operating costs Geological and geophysical expenses During 2015, we took decisive steps to adapt to the new oil price environment. Administrative expenses We reduced our 2015 capital expenditure program by 79% year-over-year and Selling expenses implemented significant cost reduction initiatives that resulted in production Depreciation 162,629 47,061 367,102 61,632 209,690 428,734 (86,742) (13,831) (37,471) (5,211) (131,419) (13,002) (45,867) (24,428) (105,557) (100,528) and operating costs being reduced by 34%, drilling costs being reduced by Write-off of unsuccessful efforts (30,084) (30,367) approximately 25%, and administrative and selling expenses being reduced by Impairment loss for non-financial assets (149,574) 39%, while achieving an average production of 20,367 boepd and increasing Other operating expense our proved reserves to 48.6 mmboe. For more information see “Item 3. Key Operating (loss)/profit Information-D. Risk Factors-Risks relating to our business- The current oil price Financial costs crisis has impacted on our operations and corporate strategy.” Foreign exchange loss (13,711) (232,491) (35,655) (33,474) (9,430) (1,849) 71,844 (27,622) (23,097) (56)% (24)% (51)% (34)% 6% (18)% (79)% 5% (1)% 1,486% 642% (424)% 29% 45% Results for the year ended December 31, 2015 were also negatively impacted Income tax benefit (expense) 17,054 (5,195) (428)% by impairment losses amounting to US$149.6 million (US$9.4 million in 2014, (Loss) Profit for the year (284,566) 15,930 (1,886)% none in 2013). See Note 36 to our Consolidated Financial Statements. Non-controlling interest (50,535) 7,845 (744)% (Loss) Profit before income tax (301,620) 21,125 (1,528)% (Loss) Profit for the year attributable Year ended December 31, 2015 compared to year ended December 31, 2014 to owners of the Company (234,031) 8,085 (2,995)% The following table summarizes certain of our financial and operating data for Oil (mbbl) the years ended December 31, 2015 and 2014. Gas (mcf ) Net production volumes Total net production (mboe) Average net production (boepd) Average realized sales price Oil (US$ per bbl) Gas (US$ per mmcf ) Average unit costs per boe (US$) Operating cost Royalties and other Production costs(1) Geological and geophysical expenses Administrative expenses Selling expenses (1) Calculated pursuant to FASB ASC 932. 5,518 11,493 7,434 20,367 5,307 11,197 7,173 19,653 32.1 4.6 10.5 1.9 12.4 2.0 5.4 0.7 77.5 6.4 16.2 3.3 19.5 1.9 6.9 3.7 4% 3% 4% 4% (59)% (28)% (35)% (42)% (36)% 5% (22)% (81)% 124 GeoPark 20F The following table summarizes certain financial and operating data. Chile Colombia Brazil Other 2015 Total Chile Colombia Brazil Other 2014 Total For the year ended December 31, Net revenue Depreciation Impairment and write-off (130,266 ) Net revenue 44,808 131,897 32,388 597 209,690 145,720 246,085 35,621 (39,227 ) (52,434 ) (49,392 ) (13,568 ) (328 ) (105,557 ) - - (179,658 ) (37,077 ) (28,772 ) (51,584 ) (10,994 ) (11,613 ) - For the year ended December 31, 2015, crude oil sales were our principal source of revenue, with 78% and 22% of our total revenue from crude oil and gas sales, respectively. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2014 to the year ended December 31, 2015. For the year ended December 31, 2015 2014 (in thousands of US$) 162,629 47,061 367,102 61,632 209,690 428,734 Year ended December 31, Change from prior year 2015 2014 % (in thousands of US$, except for percentages) 131,897 44,808 32,388 597 246,085 145,720 35,621 1,308 (114,188) (100,912) (3,233) (711) 209,690 428,734 (219,044) (46)% (69)% (9)% (54)% (51)% Consolidated Sale of crude oil Sale of gas Total By country Colombia Chile Brazil Other Total (in thousands of US$) 1,308 (254 ) (31 ) 428,734 (100,528 ) (39,797 ) GeoPark 125 Net revenue decreased 51%, from US$428.7 million for the year ended Production and operating costs December 31, 2014 to US$209.7 million for the year ended December 31, 2015, The following table summarizes our production costs for the years ended primarily as a result of lower prices. Sales of crude oil increased to 5.3 mmbbl December 31, 2015 and 2014. in the year ended December 31, 2015 compared to 5.0 mmbbl in the year ended December 31, 2014, and resulted in net revenue of US$162.6 million for the year ended December 31, 2015 compared to US$367.1 for the year ended December 31, 2014. In addition, sales of gas decreased from US$61.6 million for the year ended December 31, 2014 to US$47.1 million for the year ended December 31, 2015 due to lower prices. For the year ended December 31, % Change from prior 2015 2014 year (in thousands of US$, except for percentages) Consolidated The decrease in 2015 net revenue of US$219.0 million is mainly explained by: (including Colombia, Chile, Argentina and Brazil) • a decrease of US$114.2 million in oil sales in Colombia Royalties • a decrease of US$100.9 million in sales in Chile, including US$89.0 million in Staff costs oil sales and US$11.9 million of gas sales. Transportation costs • a decrease of US$3.2 million in sales in Brazil, related to our Rio das Contas Well and facilities maintenance operations and including US$0.6 million of oil sales and US$2.6 million of Consumables gas sales, Equipment rental all of which was due principally to lower oil and gas prices, as further described Other costs (13,155) (18,562) (4,511) (19,974) (8,591) (3,517) (18,432) (22,166) (17,731) (11,534) (25,475) (16,157) (7,563) (30,793) (41)% 5% (61)% (22)% (47)% (53)% (40)% below. Total (86,742) (131,419) (34)% Net revenue attributable to our operations in Colombia for the year ended December 31, 2015 was US$131.9 million, compared to US$246.1 million for the year ended December 31, 2014, representing 63% and 57% of our total consolidated sales. The decrease is related to a decrease in the average realized prices per barrel of crude oil from US$73.0 per barrel to US$28.8 per barrel, primarily due to lower reference international prices. This was partially offset by an increased sales of crude oil, from 3.7 mmbbl for the year ended December 31, 2014 to 4.6 mmbbl for the year ended December 31, 2015, an increase of 24%. This increase resulted mainly from the development of the Tigana field in the Llanos 34 Block. Net revenue attributable to our operations in Chile for the year ended December 31, 2015 was US$44.8 million, a 69% decrease from US$145.7 million for the year ended December 31, 2014, principally due to (1) decreased sales of crude oil of 0.7 mmbbl for the year ended December 31, 2015 compared to 1.3 mmbbl for the year ended December 31, 2014 (a decrease of 46%) due to the decline in base production, (2) decreased average realized prices per barrel of crude oil from US$89.4 per barrel for the year December 31, 2014 to US$42.2 per barrel for the year ended December 31, 2015 (a decrease of US$47.2 per barrel or a total of 53%). The decrease in the average realized price per barrel was attributable to lower international reference prices. In addition, gas sales decreased by US$11.9 million. The contribution to our net revenue during such years from our operations in Chile was 21% and 34%, respectively. Net revenue attributable to our operations in Brazil for the year ended December 31, 2015 was US$32.4 million, representing 15% of our total consolidated sales, were related to our Rio das Contas operations and were composed of 97% gas sales, amounting to US$31.4 million. 126 GeoPark 20F 2015 Year ended December 31, 2014 Chile Brazil Colombia Chile Brazil Colombia (1,973) (7,680) (2,441) (2,998) - - (10,628) (1,651) (1,851) (101) (4,030) (28,704) - - (3,407) (8,056) (8,150) (9,322) (2,068) (7,611) (6,726) (3,404) (11,253) (6,777) (4,026) (6,784) (14,157) (2,111) (97) (7,816) (48,534) (41,768) (in thousands of US$) (2,794) - - - - - (5,354) (8,148) (12,353) (13,962) (4,663) (10,969) (13,974) (7,433) (17,599) (80,953) By country Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total Production costs decreased 34%, from US$131.4 million for the year ended December 31, 2014 to US$86.7 million for the year ended December 31, 2015, primarily due to cost reduction initiatives and the impact of the depreciation of the local currencies against the US$. Production and operating costs in Colombia decreased 40%, to US$48.5 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014, primarily due to cost reduction initiatives and the impact of the depreciation of the Co$ against the US$. In addition, operating costs per boe in Colombia decreased to US$9 per boe for the year ended December 31, 2015 from US$18 per boe for the year ended December 31, 2014, due to the fact that increased production generated improved fixed cost absorption, which positively impacted production costs per boe. Production and operating costs in Chile decreased by 31%, due to cost reduction initiatives and the impact of the depreciation of the Ch$ against the US$. In the year ended December 31, 2015, in Chile, operating costs per boe increased to US$21.0 per boe from US$16.7 per boe in 2014. In the year ended December 31, 2015, the revenue mix for Chile was 65.1% oil and 34.9% gas, whereas for the same period in 2014 it was 81.1% oil and 18.9% gas. Production and operating costs in Brazil amounted to US$8.1 million for the year ended December 31, 2015 corresponding to our Rio das Contas operations. Operating costs per boe decreased to US$4 for the year ended December 31, 2015 from US$6 per boe for the year ended December 31, 2014. GeoPark 127 Geological and geophysical expenses Selling expenses decreased 79%, from US$24.4 million for year ended December 31, 2014 to US$5.2 million for the year ended December 31, 2015, Year ended December 31, Change from prior year primarily due to a change in the commercialization mix increasing sales at 2015 (in thousands of US$, except for percentages) 2014 % By country Colombia Chile Brazil Other Total (2,798) (4,749) (1,103) (5,181) (3,003) (6,241) (2,164) (1,594) (13,831) (13,002) 205 1,492 1,061 (3,587) (829) (7)% (24)% (49)% 225% 6% Exploration costs increased 6%, from US$13.0 million for the year ended By country December 31, 2014 to US$13.8 million for the year ended December 31, 2015, Colombia primarily as the result of a lower allocation to capitalized projects generated by the reduction of the capital expenditures program in 2015. Chile Brazil Other Total wellhead in our Colombian operations. In our Chilean operations, selling expenses were 56% lower compared to prior year, primarily as a result of lower production and deliveries in Chile. Operating (loss) profit Year ended December 31, Change from prior year 2015 2014 % (in thousands of US$, except for percentages) (37,227) (180,264) 6,639 67,212 11,733 10,658 (21,639) (17,759) (104,439) (191,997) (4,019) (3,880) (155)% (1,636)% (38)% 22% (232,491) 71,844 (304,335) (424)% Administrative costs By country Colombia Chile Brazil Other Total Year ended December 31, Change from prior year We recorded an operating loss of US$232.5 million for the year ended 2015 2014 % December 31, 2015, a 424% decrease from the operating profit of US$71.8 (in thousands of US$, except for percentages) million for the year ended December 31, 2014, primarily due to non-cash (10,579) (10,978) (2,936) (12,978) (11,108) (18,181) (2,760) (13,818) (37,471) (45,867) 529 7,203 (176) 840 8,396 impairments of non-financial assets, which amounted to US$149.6 million (5)% (US$104.5 million recorded in Chile and US$45.1 million in Colombia), resulting (40)% from the continuing low oil price environment and lower sales. 6% (6)% Financial costs (18)% Financial costs increased 29% to US$35.7 million for the year ended December 31, 2015 as compared to US$27.6 million for the year ended December 31, Administrative costs decreased 18%, from US$45.9 million for the year ended 2014, mainly due to the impact of lower capitalized interest costs and, to a December 31, 2014 to US$37.5 million for the year ended December 31, 2015, lesser extent, the increase of other financial costs. primarily as a result of a decrease in costs due to continuing financial discipline and cost reduction initiatives impacting consultant fees, office Foreign exchange loss expenses, directors fees and others. The reduction was achieved despite new Foreign exchange loss increased 45% to US$33.5 million for the year ended start-up costs related to operations in Peru. December 31, 2015 as compared to US$23.1 million for the year ended December 31, 2014, mainly because of the depreciation of the real over US$ denominated net debt incurred at the local subsidiary level, where the functional currency is the real . Year ended December 31, Change from prior year 2015 2014 % (in thousands of US$, except for percentages) (3,658) (1,085) - (468) (21,456) (2,470) - (502) 17,798 1,385 - 34 (5,211) (24,428) 19,217 (83)% (56)% - (7)% (79)% Selling expenses By country Colombia Chile Brazil Other Total 128 GeoPark 20F (Loss) Profit before income tax (Loss) Profit for the year Year ended December 31, Change from prior year Year ended December 31, Change from prior year 2015 (in thousands of US$, except for percentages) 2014 % 2015 (in thousands of US$, except for percentages) 2014 % By country Colombia Chile Brazil Other Total By country (38,339) (193,683) (37,980) (31,618) 61,609 13,151 (9,698) (43,937) (99,948) (162)% Colombia (206,834) (1,573)% (28,282) 12,319 292% (28)% Chile Brazil Other (38,959) (176,789) (29,623) (39,195) 40,194 17,231 (2,252 (39,243 (79,153) (197)% (194,020) (1,126)% (27,371) 1,215% 48 - (301,620) 21,125 (322,745) (1,528)% Total (284,566) 15,930 (300,496) (1,886)% For the year ended December 31, 2015, we recorded a loss before income tax For the year ended December 31, 2015, we recorded a loss of US$384.6 million of US$301.6 million, compared to a profit of US$21.1 million for the year ended as a result of the reasons described above. December 31, 2014, primarily due to losses from our Chilean, Colombian and Brazilian operations amounting to US$206.8 million, US$99.9 million and (Loss) Profit for the year attributable to owners of the Company US$28.3 million, respectively, partially offset by lower losses from our Other Loss for the year attributable to owners of the Company decreased by 2,995% operations amounting to US$12.3 million. to US$234.0 million, for the reasons described above. Loss attributable to non-controlling interest decreased by 744% to US$50.5 million for the year Income tax benefit (expense) ended December 31, 2015 as compared to the prior year. Year ended December 31, Change from prior year 2015 2014 % (in thousands of US$, except for percentages) (620) (21,415) 16,893 8,357 (7,576) 4,080 7,446 4,694 17,054 (5,195) 20,795 12,813 911 (12,270) 22,249 (97)% 314% 12% (261)% (428)% By country Colombia Chile Brazil Other Total Income tax expense decreased 428%, from US$5.2 million for the year ended December 31, 2014 to a benefit of US$17.1 million for the year ended December 31, 2015, as a result of our decreased results of operations, partially offset by non-recoverable tax loss carry-forwards amounting to US$15.5 million. Our effective tax rate for the year ended December 31, 2015 was 6% as compared to 25% in the year ended December 31, 2014. GeoPark 129 Year ended December 31, 2014 compared to year ended December 31, 2013 The following table summarizes certain of our financial and operating data for For the year ended % Change December 31, from 2014 2013 prior year the years ended December 31, 2014 and 2013. (in thousands of US$, except for percentages) Revenue Net oil sales Net gas sales Net revenue 367,102 61,632 315,435 22,918 428,734 338,353 Production and operating costs (131,419) (111,296) 16% 169% 27% 18% 146% 2% 42% 44% 177% 100% (135)% (14)% 50% (58)% (66)% (54)% (37)% (13,002) (45,867) (24,428) (100,528) (30,367) (9,430) (1,849) 71,844 (50,719 21,125 (5,195) 15,930 7,845 (5,292) (44,962) (17,252) (69,968) (10,962) - 5,343 83,964 (33,876) 50,088 (15,154) 34,934 12,413 8,085 22,521 (64)% 5,307 11,197 7,173 19,653 4,056 5,263 4,933 13,517 77.5 6.4 16.2 3.3 19.5 1.9 6.9 3.7 81.9 5.0 19.0 3.5 22.5 1.1 9.1 3.5 31% 112% 45% 45% (5)% 28% (15)% (6)% (13)% 73% (24)% 6% Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful efforts Impairment loss for non-financial assets Other operating expense Operating (loss)/profit Financial results (Loss) Profit before income tax Income tax benefit (expense) (Loss) Profit for the year Non-controlling interest (Loss) Profit for the year attributable to owners of the Company Net production volumes Oil (mbbl) Gas (mcf ) 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$) Operating cost Royalties and other Production costs(1) Geological and geophysical expenses Administrative expenses Selling expenses (1) Calculated pursuant to FASB ASC 932. 130 GeoPark 20F The following table summarizes certain financial and operating data. Chile Colombia Brazil Other 2014 Total Chile Colombia Brazil Other 2013 Total For the year ended December 31, Net revenue Depreciation Impairment and write-off 145,720 246,085 35,621 (37,077 ) (28,772 ) (51,584 ) (10,994 ) (11,613 ) - 1,308 (254 ) (31 ) 428,734 428,734 (100,528 ) (100,528) (39,797 ) (39,797) 157,491 (30,239) (7,704) 179,324 (39,406) (3,258) (in thousands of US$) 1,538 (323) - 338,353 (69,968) (10,962) Net revenue For the year ended December 31, 2014, crude oil sales were our principal source of revenue, with 86% and 14% of our total revenue from crude oil and gas sales, respectively. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2013 to the year ended December 31, 2014. For the year ended December 31, 2014 2014 (in thousands of US$) 367,102 61,632 315,435 22,918 428,734 338,353 Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) 246,085 145,720 35,621 1,308 179,324 157,491 - 1,538 428,734 338,353 66,761 (11,771) 35,621 (230) 90,381 37% (7)% 100% (15)% 27% Consolidated Sale of crude oil Sale of gas Total By country Colombia Chile Brazil Other Total Net revenue increased 27%, from US$338.4 million for the year ended December 31, 2013 to US$428.7 million for the year ended December 31, 2014, primarily as a result of (i) incorporation of 9 months of results for Rio das Contas in our Brazil operations and (ii) an increase in volumes of crude sales by 33%. Sales of crude oil increased to 5.0 mmbbl in the year ended December 31, 2014 compared to 3.8 mmbbl in the year ended December 31, 2013, and resulted in net revenue of US$367.1 million for the year ended December 31, 2014 compared to US$315.4 million for the year ended December 31, 2013. In addition, sales of gas increased from US$22.9 million for the year ended December 31, 2013 to US$61.6 million for the year ended December 31, 2014 due to the incorporation of 9 months of sales for Rio das Contas, transaction that closed in March 31, 2014. GeoPark 131 The increase in 2014 net revenue of US$90.4 million is mainly explained by: Production and operating costs • an increase of US$66.8 million in oil sales in Colombia The following table summarizes our production costs for the years ended • an increase of U$S35.6 million in sales in Brazil, related to our Rio das Contas December 31, 2014 and 2013. operations and including US$1.5 million of oil sales and US$34.1 million of gas sales. • a decrease of US$11.8 million in sales in Chile, including US$16.4 million in oil sales, partially offset by an increase in gas sales of US$4.6 million. Net revenue attributable to our operations in Colombia for the year ended December 31, 2014 was US$246.1 million, compared to US$179.3 million for Consolidated For the year ended December 31, % Change from prior 2014 2013 year (in thousands of US$, except for percentages) the year ended December 31, 2013, representing 57% and 53% of our total (including Colombia, Chile, Argentina and Brazil) consolidated sales. Such amounts were primarily due to increased sales of Royalties crude oil, from 2.4 mmbbl for the year ended December 31, 2013 to 3.7 mmbbl Staff costs for the year ended December 31, 2014, an increase of 54%. This increase Transportation costs resulted mainly from the development of the Tigana and Tua fields in the Well and facilities maintenance Llanos 34 Block. This was partially offset by a decrease in the average realized Consumables prices per barrel of crude oil from US$80.3 per barrel to US$73.0 per barrel, Equipment rental primarily due to lower reference international prices. Other costs Total (22,166) (17,731) (11,534) (25,475) (16,157) (7,563) (30,793) (17,239) (14,202) (11,392) (20,662) (14,855) (7,139) (25,807) (131,419) (111,296) 29% 25% 1% 23% 9% 6% 19% 18% Net revenue attributable to our operations in Chile for the year ended December 31, 2014 was US$145.7 million, a 7% decrease from US$157.5 million for the year ended December 31, 2013, principally due to (1) decreased sales of crude oil of 1.3 mmbbl for the year ended December 31, 2014 compared to 1.6 mmbbl for the year ended December 31, 2013 (a decrease of 16%) due to the decline in base production, partially offset by new wells drilled, (2) increased average realized prices per barrel of crude oil from US$84.3 per barrel for the year December 31, 2013 to US$89.4 per barrel for the year ended December 31, 2014 (an increase of US$5.1 per barrel or a total of 6%). The increase in the average realized price per barrel was partly attributable to lower quality discounts in the year ended December 31, 2014 as compared to the same period in 2013, partially offset by lower international reference prices. The net decreased sales of crude oil were partially offset by a US$4.6 million increase in gas sales mainly driven by higher average gas prices and to a lesser extent due to our Tierra del Fuego operations. The contribution to our net revenue during such years from our operations in Chile was 34% and 47%, respectively. Net revenue attributable to our operations in Brazil for the year ended December 31, 2014 was US$35.6 million, representing 8% of our total consolidated sales, were related to our Rio das Contas operations and were composed of 96% gas sales, amounting to US$34.1 million. 132 GeoPark 20F By country Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (1) No information is available for Brazil for 2013 as Rio das Contas was acquired in March 2014. Production and operating costs increased 18%, from US$111.3 million for the year ended December 31, 2013 to US$131.4 million for the year ended December 31, 2014, primarily due to increased costs in the Colombian operations and the addition of US$8.1 million in such costs from our Brazilian operations related to the incorporation of 9 months of our Rio das Contas operations. Production and operating costs in Colombia increased 12%, to US$81.0 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013, primarily due to increased production and deliveries in the year ended December 31, 2014. However, operating costs per boe in Colombia decreased to US$18 per boe for the year ended December 31, 2014 from US$26 per boe for the year ended December 31, 2013, due to the fact that increased production generated improved fixed cost absorption, which positively impacted the production costs per boe. Production and operating costs in Chile increased by 8%, due to the impact on fixed costs from lower oil and gas production and the startup of operations in the Tierra del Fuego Blocks. In the year ended December 31, 2014, in Chile, operating costs per boe increased to US$16.7 per boe from US$12.2 per boe in 2013. In the year ended December 31, 2014, the revenue mix for Chile was 81.1% oil and 18.9% gas, whereas for the same period in 2013 it was 85.5% oil and 14.5% gas. Production and operating costs in Brazil amounted to US$8.1 million for the year ended December 31, 2014 corresponding to our Rio das Contas operations. Operating costs per boe was US$6 for the year ended December 31, 2014. Chile 2014 Brazil Colombia Year ended December 31, 2013(1) Colombia Chile (in thousands of US$) (6,777) (4,026) (6,784) (14,157) (2,111) (97) (7,816) (41,768) (2,794) - - - - - (5,354) (8,148) (12,353) (13,962) (4,663) (10,969) (13,974) (7,433) (17,599) (7,384) (6,508) (6,456) (8,163) (1,891) - (9,661) (8,988) (4,733) (12,105) (12,886) (7,139) (8,128) (16,967) (80,953) (38,530) (72,479) GeoPark 133 Geological and geophysical expenses Selling expenses increased 42%, from US$17.3 million for year ended Year ended December 31, Change from prior year primarily due to increased production and deliveries in our Colombian December 31, 2013 to US$24.4 million for the year ended December 31, 2014, 2014 (in thousands of US$, except for percentages) 2013 % operations corresponding to sales made through the pipeline. In our Chilean operations, selling expenses were 39% lower compared to prior year, primarily as a result of lower production and deliveries in Chile. By country Colombia Chile Brazil Other Total (3,003) (6,241) (2,164) (1,594) (83) (2,054) (1,702) (1,453) (2,920) (4,187) (462) (141) (13,002) (5,292) (7,710) 3,518% 204% Operating profit (loss) 27% 10% 146% Exploration costs increased 146%, from US$5.3 million for the year ended By country December 31, 2013 to US$13.0 million for the year ended December 31, 2014, Colombia primarily due to increased staff costs amounting to US$5.3 million. Administrative costs Chile Brazil Other Total Year ended December 31, Change from prior year Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) 67,212 11,733 10,658 (17,759) 71,844 38,811 63,110 (3,107) (14,850) 28,401 (51,377) 13,765 (2,909) 83,964 (12,120) 73% (81)% 443% 20% (14)% By country Colombia Chile Brazil Other Total 2014 2013 % We recorded an operating profit of US$71.8 million for the year ended (in thousands of US$, except for percentages) December 31, 2014, a 14% decrease from US$84.0 million for the year ended (11,108) (18,181) (2,760) (13,818) (16,236) (15,193) (1,404) (12,129) (45,867) (44,962) December 31, 2013, primarily due to lower gross profit and higher exploratory 5,128 (32)% costs resulting from the write-offs of unsuccessful exploratory wells in our (2,988) (1,356) (1,689) (905) 20% 97% 14% 2% Chilean operations, partially offset by (i) higher operating profit in our Colombian operations resulting from higher production and deliveries and (ii) higher operating profit in our Brazilian operations related to the Rio das Contas acquisition that we closed on March 31, 2014. In 2014, Colombian operations were negatively impacted by non-cash impairment charges of Administrative costs increased 2%, from US$45.0 million for the year ended non-financial assets amounting to US$9.4 million related to our La Cuerva December 31, 2013 to US$45.9 million for the year ended December 31, 2014, Block, resulting from the decrease in international oil prices. primarily as a result of an increase in costs in: (1) our Chilean operations, from US$15.2 million in the year ended December 31,2013 to US$18.2 million in the Financial results, net year ended December 31, 2014, mainly due to the startup of our operations in Financial loss increased 50% to US$50.7 million for the year ended December Tierra del Fuego; (2) incorporation of our Rio das Contas operations in Brazil 31, 2014 as compared to US$33.9 million for the year ended December 31, and (3) higher corporate expenses related to our growth strategy and new 2013, due to exchange rate differences amounting to US$22 million resulting business efforts, partially offset by lower administrative expenses in Colombia. from the depreciation of the Brazilian real in addition to increased interest expenses, resulting from higher average indebtedness. In addition, financial results for the year ended December 31, 2013 included accelerated debt issuance costs in connection with the redemption of the Notes due 2015 in an Year ended December 31, Change from prior year amount of US$8.6 million following the issuance of Notes due 2020 in 2014 2013 % February 2013. (in thousands of US$, except for percentages) (21,456) (2,470) - (502) (12,677) (4,062) - (513) (8,779) 1,592 - 11 (24,428) (17,252) (7,176) 69% (39)% - (2)% 42% Selling expenses By country Colombia Chile Brazil Other Total 134 GeoPark 20F Profit before income tax Profit for the year Year ended December 31, Change from prior year Year ended December 31, Change from prior year 2014 (in thousands of US$, except for percentages) 2013 % 2014 (in thousands of US$, except for percentages) 2013 % By country Colombia Chile Brazil Other Total 61,609 13,151 (9,698) (43,937) 21,125 31,049 49,965 (1,937) (28,989) 30,560 (36,814) (7,761) (14,948) By country 98% Colombia (74)% 401% Chile Brazil 52% Other 50,088 (28,963) (58)% Total 40,194 17,231 (2,252 (39,243 15,930 13,179 45,844 (1,409) 27,015 (28,613) (843) (22,680) (16,563) 34,934 (19,004) 205% (62)% 60% 73% (54)% For the year ended December 31, 2014, we recorded a profit before income tax For the year ended December 31, 2014, we recorded a profit of US$15.9 of US$21.1 million, a decrease of 58% from US$50.1 million for the year ended million, a 54% decrease from US$34.9 million for the year ended December 31, December 31, 2013, primarily due lower profits from our Chilean, Brazilian and 2013, as a result of the reasons described above. Other operations amounting to US$36.8 million, US$7.8 million and US$14.9 million, respectively, partially offset by increased profits from our Colombian Profit for the year attributable to owners of the Company operations amounting to US$30.6 million. Profit for the year attributable to owners of the Company decreased by 64% to Income tax By country Colombia Chile Brazil Other Total US$8.1 million, for the reasons described above. Profit attributable to non-controlling interest decreased by 37% to US$7.8 million for the year ended December 31, 2014 as compared to the prior year. Year ended December 31, Change from prior year 2014 2013 % B. Liquidity and capital resources (in thousands of US$, except for percentages) (21,415) 4,080 7,446 4,694 (17,870) (4,121) 528 6,309 (5,195) (15,154) (3,545) 8,201 6,918 (1,615) 9,959 Overview 20% Our financial condition and liquidity is and will continue to be influenced by a (199)% variety of factors, including: 1,310% • changes in oil and natural gas prices and our ability to generate cash flows (26)% from our operations; (66)% • our capital expenditure requirements; • the level of our outstanding indebtedness and the interest we are obligated Income tax decreased 66%, from US$15.2 million for the year ended December to pay on this indebtedness; and 31, 2013 to US$5.2 million for the year ended December 31, 2014, as a result of • changes in exchange rates which will impact our generation of cash flows our decreased results of operations in Chile and Brazil, partially offset by from operations when measured in US$, and the real. higher results of operations in our Colombian operations. Our effective tax rate for the year ended December 31, 2014 was 25% as compared to 30% in the Our principal sources of liquidity have historically been contributed year ended December 31, 2013 due to higher charges from deferred income shareholder equity, debt financings and cash generated by our operations. taxes in the year ended December 31, 2014 mainly resulting from the effect of currency translation on tax base. Since 2005 to 2015, we have raised approximately US$200 million in equity offerings at the holding company level and more than US$564 million through debt arrangements with multilateral agencies such as the IFC, gas prepayment facilities with Methanex, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity. We have also raised US$175.7 million to date through our strategic partnership with LGI following the sale of minority interests in our Colombian and Chilean operations. GeoPark 135 We initially funded our 2012 expansion into Colombia through a US$37.5 hand. Should our operating cash flow decline due to unforeseen events, million loan, cash on hand and a subsequent sale of a minority interest in our including delivery restrictions or a protracted downturn in oil and gas prices, Colombian operations to LGI. We subsequently restructured our outstanding we would examine measures such as further capital expenditure program debt in February 2013, by issuing US$300.0 million aggregate principal reductions, pre-sale agreements, disposition of assets, or issuance of equity, amount of Notes due 2020, a portion of the proceeds of which we used to among others. prepay the US$37.5 million loan and to redeem all of our outstanding Notes due 2015. See “Item 4. Information on the Company-B. Business Overview- Capital expenditures Significant agreements-Agreements with LGI.” We have funded our capital expenditures with proceeds from equity offerings, In February 2014, we commenced trading on the NYSE and raised US$98 cash generated from our operations. We expect to incur substantial expenses million (before underwriting commissions and expenses), including the and capital expenditures as we develop our oil and natural gas prospects and credit facilities, debt issuances and pre-sale agreements, as well as through over-allotment option granted to and exercised by the underwriters, through acquire additional assets. the issuance of 13,999,700 common shares. In the year ended December 31, 2015, we made total capital expenditures of In March 2014, we borrowed US$70.5 million pursuant to a five-year term US$48.8 million (US$30.7 million, US$12.4 million, US$0.1 million and US$5.6 (including annual principal amortization in March and September of each year million in Colombia, Chile, Argentina and Brazil, respectively) for the year 2015. starting in 2015) variable interest secured loan, secured by the benefits we receive under the Purchase and Sale Agreement for Natural Gas with In the year ended December 31, 2014, we made total capital expenditures of Petrobras, equal to 6-month LIBOR + 3.9% to finance part of the purchase price US$238.0 million (US$161 million, US$66 million, and US$11 million in Chile, of our Rio das Contas acquisition, and funded the remaining amount with cash Colombia and Brazil, respectively). In addition to the above, in 2014 we on hand. In March 2015, we reached an agreement to: (i) extend the principal completed the acquisition of Rio das Contas for US$115 million (net of cash payments that were due in 2015 (amounting to approximately US$15 million), acquired). which will be divided pro-rata during the remaining principal installments, starting in March 2016 and (ii) to increase the variable interest rate equal to Cash flows the 6-month LIBOR + 4.0%. The following table sets forth our cash flows for the periods indicated: In February, 2013, we issued US$300.0 million aggregate principal amount of senior secured notes due 2020. The Notes due 2020 mature on February 11, 2020 and bear interest at a fixed rate of 7.50% and a yield of 7.625% per year. Interest on the Notes due 2020 is payable semi-annually in arrears on February 11 and August 11 of each year. The Indenture governing our Notes due 2020 Cash flows provided by (used in) contain incurrence-based limitations on the amount of indebtedness we can Operating activities incur. During 2015, and impacted by the current low oil price environment, our Investing activities leverage ratio (as defined in the Indenture) and the interest coverage (as Financing activities defined in the Indenture) did not meet certain thresholds included in the 2020 Net (decrease) increase in cash Year ended December 31, 2015 2014 2013 (in thousands of US$) 25,895 230,746 127,295 (48,842) (18,022) (344,041) (208,500) 124,716 164,018 Bond Indenture. This situation may limit our capacity to incur additional and cash equivalents (40,969) 11,421 82,813 indebtedness, other than permitted debt, as specified in the indenture governing the Notes. Cash flows provided by operating activities For the year ended December 31, 2015, cash provided by operating activities In December 2015, we entered into an offtake and prepayment agreement was US$25.9 million, a 88.8% decrease from US$230.7 million for the year with Trafigura under which we will sell a portion of our Colombian crude oil ended December 31, 2014, resulting from the decline in oil and natural gas production to Trafigura in exchange for advance payments of up to US$100 prices in 2015 as compared to 2014. million, subject to applicable volumes corresponding to the terms of the agreement. Funds committed will be made available to us upon request and For the year ended December 31, 2014, cash provided by operating activities will be repaid by us through future oil deliveries over the period of the was US$230.7 million, a 81.3% increase from US$127.3 million for the year contract, which is 2.5 years with a 6-month grace period. ended December 31, 2013, mainly resulting from increased production from our Colombian operations and the acquisition of Rio das Contas in Brazil. We believe that our current operations and 2016 capital expenditures program can be funded from cash flow from existing operations and cash on 136 GeoPark 20F Cash flows used in investing activities Indebtedness For the year ended December 31, 2015, cash used in investing activities was As of December 31, 2015 and 2014, we had total outstanding indebtedness US$48.8 million, a 85.8% decrease from US$344.0 million for the year ended of US$378.7 million and US$369.6 million, respectively, as set forth in the December 31, 2014. This decrease was related to our Brazilian acquisitions, table below. which occurred in the first quarter of 2014. This amount was complemented by a decrease of US$189.2 million in capital expenditures mainly resulting from lower wells drilled in 2015 as compared to 2014 (7 wells drilled in 2015 compared to 53 wells drilled in 2014). For the year ended December 31, 2014, cash used in investing activities was Bond GeoPark Latin America US$344.0 million, a 64.9% increase from US$208.5 million for the year ended Agencia en Chile (Notes due 2020) December 31, 2013. This increase was primarily related to our Brazilian Banco de Chile acquisitions, which occurred in the first quarter of 2014. This amount was Rio das Contas Credit Facility complemented by an increase of US$22.8 million in capital expenditures Total relating to the drilling of 53 new wells (32 in Chile and 21 in Colombia) and BCI Loans As of December 31, 2015 2014 (in thousands of US$) - 90 302,495 300,963 7,036 69,142 - 68,540 378,673 369,593 facilities construction, as compared to the drilling of 39 wells (17 in Chile and Our material outstanding indebtedness as of December 31, 2015 is described 22 in Colombia) for the year ended December 31, 2013. below. Cash flows provided by financing activities Notes due 2020 Cash used in financing activities was US$18.0 million for the year ended December 31, 2015, compared to cash provided by financing activities of General US$124.7 million for the year ended December 31, 2014. This change was On February 11, 2013, we issued US$300.0 million aggregate principal principally the result of cash received in the 2014 period from the funds amount of senior secured notes due 2020. The Notes due 2020 mature on recovered from our initial public offering and listing of our common shares on February 11, 2020 and bear interest at a fixed rate of 7.50% and a yield of the NYSE in February 2014 amounting to US$90.9 million and the US$70.5 7.625% per year. Interest on the Notes due 2020 is payable semi-annually in million loan entered into with Itaú BBA International plc used to fund the Rio arrears on February 11 and August 11 of each year. das Contas acquisition. Cash used in financing activities in 2015 is composed mainly of interest payments amounting to US$25.8 million, partially offset by Ranking US$7.0 million of proceeds from borrowings. The Notes due 2020 constitute senior obligations of Agencia, secured by a first lien on certain collateral (as described below). The Notes due 2020 rank equally Cash provided by financing activities was US$124.7 million for the year ended in right of payment with all senior existing and future obligations of Agencia December 31, 2014, compared to cash provided by financing activities of (except those obligations preferred by operation of Bermuda and Chilean law, US$164.0 million for the year ended December 31, 2013. This change was including, without limitation, labor and tax claims); effectively senior to all principally the result of cash received in the 2013 period from the issuance of unsecured debt of Agencia and GeoPark Latin America, to the extent of the US$300.0 million of our Notes due 2020 (partially offset by the early value of the collateral; senior in right of payment to all existing and future redemption of our Notes due 2015 and the repayment of the Banco Itaú BBA subordinated indebtedness of Agencia and GeoPark Latin America; and Credit Agreement, in an aggregate amount of US$175.0 million) and an effectively junior to any future secured obligations of Agencia and its increase of US$36.6 million in cash from LGI pertaining principally to its subsidiaries (other than additional notes issued pursuant to the indenture investment in our Colombian and Chilean operations. These were partially governing the Notes due 2020) to the extent secured by assets constituting offset by funds recovered from our initial public offering and listing of our with a security interest on assets not constituting collateral, in each case to the common shares on the NYSE in February 2014 amounting to US$90.9 million extent of the value of the collateral securing such obligations. and the US$70.5 million loan entered into with Itaú BBA International plc used to fund the Rio das Contas acquisition. Guarantees The Notes due 2020 are guaranteed unconditionally on an unsecured basis by us, all of our wholly-owned subsidiaries, and any subsidiary that guarantees any of our debt, subject to certain exceptions. GeoPark 137 Collateral Covenants The notes are secured by a first-priority perfected security interest in certain The Notes due 2020 contain customary covenants, which include, among collateral, which consists of: 80% of the equity interests of each of GeoPark others, limitations on the incurrence of debt and disqualified or preferred Chile and GeoPark Colombia held by Agencia, and loans of the net proceeds of stock, restricted payments (including restrictions on our ability to pay the Notes due 2020 made by Agencia to each of GeoPark Fell and GeoPark dividends), incurrence of liens, transfer, prepayment or modification of Llanos SAS. Except for certain immaterial subsidiaries and other exceptions, we certain collateral, guarantees of additional indebtedness, the ability of and Agencia are also required to pledge the equity interests of our subsidiaries. certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into The Notes due 2020 are also secured on a first-priority basis by intercompany another company. loans, disbursed to subsidiaries, in an aggregate amount at any one time that does not exceed US$300.0 million. Optional redemption In the event the Notes due 2020 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indenture At any time prior to February 11, 2017, we may, at our option, redeem any of governing the Notes due 2020, certain of these restrictions, including, among the Notes due 2020, in whole or in part, at a redemption price equal to 100% others, the limitations on incurrence of debt and disqualified or preferred of the principal amount of such Notes due 2020 plus an applicable stock, restricted payments (including restrictions on our ability to pay “make-whole” premium, plus accrued and unpaid interest (including, dividends), the ability of certain subsidiaries to pay dividends, asset sales and additional amounts), if any, as such term is defined in the indenture certain transactions with affiliates will no longer be applicable. governing the Notes due 2020, if any, to the redemption date. At any time and from time to time on or after February 11, 2017, we may, at covenants that provide, among other things, that, the debt to EBITDA ratio our option, redeem all or part of the Notes due 2020, at the redemption should not exceed 2.5 and the EBITDA to Interest ratio should exceed 3.5. As prices, expressed as percentages of principal amount, set forth below, plus of the date of this annual report, the Company’s debt to EBITDA ratio was 5.1 accrued and unpaid interest thereon (including additional amounts), if any, and the EBITDA to interest ratio was 2.4, primarily due to the lower oil prices to the applicable redemption date, if redeemed during the 12-month period that impacted the Company’s EBITDA generation. Failure to comply with the beginning on February 11 of the years indicated below: incurrence test covenants does not trigger an event of default. However, this The indenture governing our Notes due 2020 includes incurrence test Year 2017 2018 2019 and after situation may limit our capacity to incur additional indebtedness, as Percentage specified in the indenture governing the Notes, other than certain categories 103.750% of permitted debt. We must test incurrence covenants before incurring 101.875% additional debt or performing certain corporate actions including but not 100.000% limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions). As of the date of this annual In addition, at any time prior to February 11, 2016, we may, at our option, report, we are in compliance with all indenture provisions. redeem up to 35% of the aggregate principal amount of the Notes due 2020 (including any additional notes) at a redemption price of 107.50% of the Events of default principal amount thereof, plus accrued and unpaid interest (including Events of default under the indenture governing the Notes due 2020 additional amounts) if any to the redemption date, with the net cash proceeds include: the nonpayment of principal when due; default in the payment of of one or more equity offerings; provided that: (1) Notes due 2020 in an interest, which continues for a period of 30 days; failure to make an offer aggregate principal amount equal to at least 65% of the aggregate principal to purchase and thereafter accept tendered notes following the amount of Notes due 2020 issued on the first issue date remain outstanding occurrence of a change of control or as required by certain covenants in immediately after the occurrence of such redemption; and (2) the redemption the indenture governing the Notes due 2020; the notes, or the security must occur within 90 days of the date of the closing of such equity offering. documents in relation thereto that continues for a period of 60 Change of control consecutive days after written notice to Agencia; cross payment default relating to debt with a principal amount of US$15.0 million or more, and Upon the occurrence of certain events constituting a change of control, we cross-acceleration default following a judgment for US$15.0 million or are required to make an offer to repurchase all outstanding Notes due 2020, more; bankruptcy and insolvency events; invalidity or denial or at a purchase price equal to 101% of the principal amount thereof plus any disaffirmation of a guarantee of the notes; and failure to maintain a accrued and unpaid interest (including any additional amounts payable in perfected security interest in any collateral having a fair market value in respect thereof ) thereon to the date of purchase. excess of US$15.0 million, among others. The occurrence of an event of 138 GeoPark 20F default would permit or require the principal of and accrued interest on Other Agreements the Notes due 2020 to become or to be declared due and payable. In December 2015, we entered into an offtake and prepayment agreement Banco de Chile with Trafigura under which we sell and deliver a portion of our Colombian crude oil production. Pricing will be determined by future spot market prices, During December 2015, we entered into a loan agreement with Banco de net of transportation costs. The agreement also provides us with prepayment Chile for US$7.0 million to finance the start-up of the new Ache gas field in of up to US$100 million from Trafigura. Funds committed will be made the Fell Block. The interest rate applicable to this loan is LIBOR plus 2.35% per available to us upon request and will be repaid by us on a monthly basis year. The interest and the principal will be paid on a monthly basis with a through future oil deliveries over the period of the contract, which is 2.5 6-month grace period and final maturity on December 2017. years, including a 6-month grace period. According to the terms of the BCI Mortgage Loan prepayment agreement, we are required to pay interest of LIBOR plus 5% per year on outstanding amounts. In addition, under the prepayment agreement, During October 2007, GeoPark executed a mortgage loan agreement with we are required to maintain certain coverage ratios linking: (i) future Banco de Crédito e Inversiones (BCI), a Chilean private bank, for the payments to the value of estimated future oil deliveries (net of acquisition of the operational base in the Fell Block. The loan was granted in transportation discounts) during the term of the offtake agreement and (ii) Ch$ and is repayable over a period of 8 years. The interest rate applicable to collections to payments within specified periods, with the possibility of this loan is 6.6%. The mortgage loan was fully repaid on October 2015. delivering additional volumes to meet such ratios in the upcoming 3-month period. As of April 15, 2016, outstanding amounts related to the prepayment LGI Line of Credit agreement amount to US$10 million. As of December 31, 2015, the aggregate outstanding amount under the LGI Line of Credit was US$21.0 million. This corresponds to a loan granted by LGI C. Research and development, patents and licenses, etc. to GeoPark Chile for financing Chilean operations in our Tierra del Fuego See “Item 4. Information on the Company--B. Business Overview” and “Item 4. blocks. The maturity of this loan is July 2020 and the applicable interest rate Information on the Company-B. Business Overview-Title to Properties.” is 8% per year. See “Item 4. Information on the Company-B. Business Overview-Significant For a discussion of Trend information, see “-A. Operating Results-Factors agreements-Agreements with LGI.” affecting our results of operations.” D. Trend information Rio das Contas Credit Facility E. Off-balance sheet arrangements We financed our Rio das Contas acquisition in part through our Brazilian We did not have any off-balance sheet arrangements as of December 31, subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das 2014 or as of December 31, 2015. Contas Credit Facility”) with Itaú BBA International plc, which is secured by the benefits GeoPark receives under the Purchase and Sale Agreement for F. Tabular disclosure of contractual obligations Natural Gas with Petrobras. The facility matures five years from March 28, In accordance with the terms of our concessions, we are required to pay 2014, which was the date of disbursement and bears interest at a variable royalty (1) in connection with crude oil production in Colombia, to the interest rate equal to the 6-month LIBOR + 3.9%. The facility agreement Colombian government, equivalent to a rate which ranges between 6%-8%, includes customary events of default, and subject our Brazilian subsidiary to (2) in connection with crude oil and gas production in Chile, to the Chilean customary covenants, including the requirement that it maintain a ratio of government, equivalent to approximately 5% of crude oil production and 3% net debt to EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. of gas production Fell and 5% for TdF and (3) in connection with gas sales in The credit facility also limits the borrower’s ability to pay dividends if the Brazil, to the Brazilian government, equivalent to 7.5%. ratio of net debt to EBITDA is greater than 2.5x. We have the option to prepay the facility in whole or in part, at any time, subject to a pre-payment fee to be determined under the contract. In March 2015, we reached an agreement to: (i) extend the principal payments that were due in 2015 (amounting to approximately US$15 million), which will be divided pro-rata during the remaining principal installments, starting in March 2016 and (ii) to increase the variable interest rate equal to the 6-month LIBOR + 4.0%. As a result of the above, in March 2016 we paid US$10 million corresponding to principal payments under the current principal amortization schedule. GeoPark 139 The table below sets forth our committed cash payment obligations as of December 31, 2015. Less than One to Three to More than Total one year three years five years five years (in thousands of US$) 479,272 42,865 83,413 352,994 - 23,900 12,878 8,257 2,456 309 78,210 12,200 66,010 - - Debt obligations(1) Operating lease obligations(2) Pending investment commitments(3) Asset retirement obligations 31,617 1,153 5,340 5,754 19,370 Total contractual obligations 612,999 69,096 163,020 361,204 19,679 (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$25.2 million; one to three years: US$46.6 million and three to five years: US$45.7 million. At December 31, 2015 the outstanding long-term borrowing affected by variable rates amounted to US$76.2 million representing 20% of total borrowings, which was composed of the loan from Itaú International BBA plc and the loan from Banco de Chile that has a floating interest rate based on LIBOR. 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 non-operated blocks in Argentina and the Llanos 62, VIM-3, and Llanos 34 Blocks in Colombia. See “Item 4. Information on the Company-B. Business overview-Our operations” and Note 31(b) to our Consolidated Financial Statements. G. Safe harbor See “Forward-Looking Statements.” 140 GeoPark 20F Directors, senior management and employees ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES A. Directors and senior management Board of directors Our Board of Directors is composed of seven members. At every annual general meeting, one third of the Directors retire from office. From the date of the annual general meeting following the effective date of the listing of our Common Shares on the NYSE, 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 2016. The current members of the Board of Directors were appointed at our annual general meeting held on June 30, 2015. The table below sets forth certain information concerning our current board of directors. All ages are as of March 31, 2016. Name Gerald E. O’Shaughnessy James F. Park Carlos A. Gulisano(3) Juan Cristóbal Pavez(1)(2) Peter Ryalls(1)(2) Robert Bedingfield(1)(2) Pedro Aylwin Chiorrini Position Chairman and Director Chief Executive Officer, Deputy Chairman and Director Director Director Director Director Director, Director of Legal and Governance, Corporate Secretary Age At the Company since 67 60 65 45 65 67 56 2002 2002 (3)2010 2008 2006 2015 2003 (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. Biographical information of the current members of our Board of Directors is set forth below. Unless otherwise indicated, the current business addresses for our directors is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile. GeoPark 141 Gerald E. O’Shaughnessy has been our Chairman and a member of our board Carlos Gulisano has been a member of our board of directors since June 2010. of directors since he co-founded the company in 2002. Following his Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate degree in graduation from the University of Notre Dame with degrees in government petroleum engineering and a PhD in geology from the University of Buenos (1970) and law (1973), Mr. O’Shaughnessy was engaged in the practice of law Aires and has authored or co-authored over 40 technical papers. He is a former in Minnesota. Mr. O’Shaughnessy has been active in the oil and gas business adjunct professor at the Universidad del Sur, a former thesis director at the over his entire business career, starting in 1976 with Lario Oil and Gas University of La Plata, and a former scholarship director at CONICET, the Company, where he served as Senior Vice President and General Counsel. He national technology research council, in Argentina. Dr. Gulisano is a respected later formed the Globe Resources Group, a private venture firm whose leader in the fields of petroleum geology and geophysics in South America subsidiaries provided seismic acquisition and processing, well rehabilitation and has over 35 years of successful exploration, development and services, sophisticated logistical operations and submersible pump works for management experience in the oil and gas industry. In addition to serving as Lukoil and other companies active in Russia during the 1990s. Mr. an advisor to GeoPark since 2002 and as Managing Director from February O’Shaughnessy is also founder and owner of BOE Midstream, LLC, which owns 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera Argentina San and operates the Bakken Oil Express, the largest crude by rail terminal in North Jorge S.A. and Chevron San Jorge S.A. and has led teams credited with Dakota, serving oil producers and marketing companies active in the Bakken significant oil and gas discoveries, including those in the Trapial field in Shale Oil play. Over the past 25 years, Mr. O’Shaughnessy has also founded and Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador, Colombia, operated companies engaged in banking, wealth management products and Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also an services, investment desktop software, computer and network security, and independent consultant on oil and gas exploration and production. green clean technology, as well as other venture investments, Mr. O’Shaughnessy has also served on a number of non-profit boards of directors, Juan Cristóbal Pavez has been a member of our board of directors since including the Board of Economic Advisors to the Governor of Kansas, the I.A. August 2008. He holds a degree in commercial engineering from the Pontifical O’Shaughnessy Family Foundation, the Wichita Collegiate School, the Institute Catholic University of Chile and a MBA from the Massachusetts Institute of for Humane Studies, The East West Institute and The Bill of Rights Institute and Technology. He has worked as a research analyst at Grupo CB and later as a is a member of the Intercontinental Chapter of Young Presidents Organization portfolio analyst at Moneda Asset Management. In 1998, he joined Santana, an and World Presidents’ Organization. investment company, as Chief Executive Officer, where he focused mainly on investments in capital markets and real estate. While at Santana, he was James F. Park has served as our Chief Executive Officer and as a member of appointed Chief Executive Officer of Laboratorios Andrómaco, one of Santana’s our board of directors since co-founding the Company in 2002. He has main assets. In 1999, Mr. Pavez co-founded Eventures, an internet company. extensive experience in all phases of the upstream oil and gas business, with a Since 2001, he has served as Chief Executive Officer at Centinela, a company strong background in the acquisition, implementation and management of with a diversified global portfolio of investments, with a special focus in the international joint ventures in North America, South America, Asia, Europe and energy industry, through the development of wind parks and run-of-the-river the Middle East. He holds a degree in geophysics from the University of hydropower plants. Mr. Pavez is also a board member of Grupo Security, Vida California at Berkeley and has worked as a research scientist in earthquake and Security and Hidroelétrica Totoral. Over the last few years he has been a board tectonic at the University of Texas. In 1978, Mr. Park joined Basic Resources member of several companies, including Quintec, Enaex, CTI and Frimetal. International Limited, an oil and gas exploration company, which pioneered the development of commercial oil and gas production in Central America. As a senior executive of Basic Resources International Limited, Mr. Park was closely involved 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. He remained a member of the board of directors of Basic Resources International Limited until the company was sold in 1997. Mr. Park is also a member of the board of directors of Energy Holdings and has also been involved in oil and gas projects in California, Louisiana, Argentina, Yemen and China. Mr. Park is a member of the AAPG and SPE and has lived in Latin America since 2002. 142 GeoPark 20F Peter Ryalls has been a member of our board of directors since April 2006. Mr. Pedro Aylwin has served as a member of our board of directors since July 2013 Ryalls started his career working as a wireline engineer for Schlumberger in and as our Director of Legal and Governance since April 2011. From 2003 to West Africa. Returning to the UK in 1976 to study for his Master’s degree in 2006, Mr. Aylwin worked for us as an advisor on governance and legal matters. Petroleum Engineering at Imperial College, London following which he joined Mr. Aylwin holds a degree in law from the Universidad de Chile and an LLM Mobil North Sea. He moved to Unocal Corporation in 1979 where he held from the University of Notre Dame. Mr. Aylwin has extensive experience in the increasingly senior positions, including as Managing Director of Unocal UK in natural resources sector. Mr. Aylwin is also a partner at the law firm Aylwin, Aberdeen, Scotland, and where he developed extensive experience in offshore Mendoza, Luksic, Valencia Abogados in Santiago, Chile, where he represented production and drilling operations. In 1994, Mr. Ryalls represented Unocal mining, chemical and oil and gas companies in numerous transactions. From Corporation in the Azerbaijan International Operating Company as Vice 2006 until 2011, he served as Lead Manager and General Counsel at BHP President of Operations and was responsible for production, drilling, reservoir Billiton, Base Metals, where he was in charge of legal and corporate engineering and logistics. In 1998, Mr. Ryalls became General Manager for governance matters on BHP Billiton’s projects, operations and natural resource Unocal in Argentina. He also served as Vice President of Unocal’s Gulf of Mexico assets in South America, North America, Asia, Africa and Australia. onshore oil and gas business and as Vice President of Global Engineering and Construction, where he was responsible for the implementation of all major capital projects ranging from deep water developments in Indonesia and the Gulf of Mexico to conventional oil and gas projects in Thailand. Mr. Ryalls is also an Independent Petroleum Consultant advising on international oil and gas development projects both onshore and offshore. Robert Bedingfield has been a member of our board of directors since March 2015. He holds a degree in Accounting from the University of Maryland and is a Certified Public Accountant. Until his retirement in June 2013, he was one of Ernst & Young’s most senior Global Lead Partners with more than 40 years of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices, as well as serving on Ernst & Young’s Senior Governing Board. He has extensive experience serving Fortune 500 companies; including acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times an Executive Committee Member, and the Audit Committee Chair of the University of Maryland at College Park Board of Trustees. Mr. Bedingfield served on the National Executive Board (1995 to 2003) and National Advisory Council (since 2003) of the Boy Scouts of America. Since 2013, Mr. Bedingfield has also served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). GeoPark 143 Executive officers Our executive officers are responsible for the management and representation of our company. The table below sets forth certain information concerning our executive officers. All ages are as of March 31, 2016. Name James F. Park Andrés Ocampo Pedro Aylwin Chiorrini Augusto Zubillaga Alberto Matamoros Marcela Vaca Carlos Murut Salvador Minniti Horacio Fontana Agustina Wisky Guillermo Portnoi Pablo Ducci Raúl Droznes Position Chief Executive Officer and Director Chief Financial Officer Director, Director of Legal and Governance, and Corporate Secretary Chief Operating Officer Director for Argentina, Brazil, Chile and Peru Director for Colombia Director of Development Director of Exploration Director of Drilling Director of People Director of Business Management Director of Capital Markets Director of New Business Age At the Company since 60 38 56 46 44 47 59 61 58 38 40 36 67 2002 2010 2003 2006 2014 2012 2006 2007 2008 2002 2006 2012 2014 Biographical information of the members of our executive officers is set forth papers, including papers on electrical submersible pump optimization, below. Unless otherwise indicated, the current business addresses for our corrosion control, water handling and intelligent production systems. executive officers is Nuestra Señora de los Ángeles 179, Las Condes, Santiago, Chile. Alberto Matamoros has been our Director for Argentina, Brazil, Chile and Peru Andrés Ocampo has served as our Chief Financial Officer since November since March 2016 and Director for Chile since January 2015. He is an industrial 2013. He previously served as our Director of Growth and Capital (from engineer and MBA, with more than 17 years of experience in the Oil & Gas January 2011 through October 2013), and has been with our company since industry. He started his career in the Argentinian oil company ASTRA, as a July 2010. Mr. Ocampo graduated with a degree in Economics from the Production Engineer of La Ventana-Vizcacheras Block in the province of Universidad Católica Argentina. He has more than 13 years of experience in Mendoza (1997-2000). He then joined Chevron, where he worked as a business and finance. Before joining our company, Mr. Ocampo worked at Production Engineer in El Trapial Block in the province of Neuquén for three Citigroup and served as Vice President Oil & Gas and Soft Commodities at years. Later, he became a Field Engineering Manager, also for three years, in Crédit Agricole Corporate & Investment Bank. Buenos Aires, and then moved to Kern County, California, to lead the production team. His experience in Chevron enabled him to manage different Augusto Zubillaga has served as our Chief Operating Officer since May technical and administrative teams, designing and executing working plans 2015. He previously served in other management positions throughout the focused in the optimization of resources. In 2014, he joined GeoPark to be part Company including as Operations Director, Argentina Director and of the Corporate Operation team before being selected as the new Country Production Director. He is a petroleum engineer with 20 years of experience Manager of GeoPark in Chile. Matamoros holds a degree in Industrial in production, engineering, well completions, corrosion control, reservoir Engineering from the Universidad Nacional del Sur and an MBA in IAE, from management and field development. He has a degree in petroleum the Business School of Universidad Austral of Buenos Aires, Argentina. engineering from the Instituto Tecnológico de Buenos Aires. Prior to joining our company, Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. Marcela Vaca has been our Director for Colombia since August 2012. Ms. Vaca and Chevron San Jorge S.A. At Chevron San Jorge S.A., he led multi- holds a degree in law from Pontificia Universidad Javeriana in Bogotá, disciplinary teams focused on improving production, costs and safety, and Colombia, a Master’s Degree in commercial law from the same university and was the leader of the Asset Development Team, which was responsible for an LLM from Georgetown University. She has served in the legal departments creating the field development plan and estimating and auditing the oil of a number of companies in Colombia, including Empresa Colombiana de and gas reserves of the Trapial field in Argentina. Mr. Zubillaga was also part Carbon Ltda (which later merged with INGEOMINAS), and from 2000 to 2003, of a Chevron San Jorge S.A. team that was responsible for identifying she served as Legal and Administrative Manager at GHK Company Colombia. business opportunities and working with the head office on the Prior to joining our company in 2012, Ms. Vaca served for nine years as General establishment of best business practices. He has authored several industry Manager of the Hupecol Group where she was responsible for supervising all 144 GeoPark 20F areas of the company as well as managing relationships with Ecopetrol, ANH, University of Chile and a master’s degree in business administration from Duke the Colombian Ministry of Mines and Energy, the Colombian Ministry of University. From 2004 to 2009, Mr. Ducci worked as a Corporate Finance Environment and other governmental agencies. At the Hupecol Group, Ms. Analyst and Corporate Finance Associate with Celfin Capital. In 2010, he Vaca was also involved in the structuring of the Hupecol Group’s asset worked as an Associate for Anka Funds, and from 2011 to 2012, he served as development and sales strategy. Vice President of Development for Falabella Retail. Carlos Murut has been our Director of Development since January 2012. He Raúl Droznes has served as our Director of New Business since August 2014. previously served as our Development Manager. Mr. Murut holds a master’s Mr. Droznes holds a degree in Finance and an MBA from Universidad de degree in petroleum geology from the University of Buenos Aires where he Buenos Aires. He has more than 27 years of experience in the oil & gas industry. also undertook postgraduate studies in reservoir engineering, specializing in Before joining GeoPark, he worked for 26 years in Tecpetrol S.A. (oil and gas field exploitation. He also completed a Business Management Development subsidiary of the Techint Group) where he acted as Director of Business Program at Austral University. Mr. Murut has over 31 years of experience Development, a role in which he was responsible for worldwide acquisitions working for international and major oil companies, including YPF S.A., and divestures of oil and gas fields. Prior to that, he worked as the New Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. Ventures & Finance Manager and was responsible for development of new Salvador Minniti has been our Director of Exploration since January 2012. He part in start up operations of the company in Venezuela, Ecuador, Peru, Bolivia, previously served as our Exploration Manager. He holds a bachelor degree in Colombia and Brazil. Prior to joining Tecpetrol S.A., he worked as Vice President geology from National University of La Plata and has a graduate degree from of International Telephone & Telegraph (“ITT”) in the United States and was the Argentine Oil and Gas Institute in oil geology. Mr. Minniti has over 31 years responsible for financial operations for manufacturing plants in Taiwan, Puerto businesses in the international división of Tecpetrol S.A., which involved taking of experience in oil exploration and has worked with YPF S.A., Petrolera Rico, Germany and England. Argentina San Jorge S.A. and Chevron Argentina. Horacio Fontana has been our Corporate Drilling Manager since March 2012. He previously served as our Engineer Manager. He holds a degree in civil Executive compensation B. Compensation engineering from Rosario National University and is also a graduate from the For the year ended December 31, 2015, we accrued or paid approximately Argentine Oil and Gas Institute, National University of Buenos Aires, with a US$4.8 million, in the aggregate, to the members of our board of directors specialty in oilfield exploitation and an extensive background in drilling (including our executive directors) for their services in all capacities. During operations. He has recently taken part in a Management Development this same period, we accrued or paid approximately US$8.5 million, in the Program at IAE Business School of Austral University. Mr. Fontana has over 26 aggregate, to the members of our senior management (excluding our years of drilling experience in major Argentine companies such as YPF S.A., executive directors) for their services in all capacities. An amount of US$0.4 Petrolera Argentina San Jorge and Chevron. million corresponds to the accrual or payment for discretionary bonus payments granted to the Company’s executive directors based on the Agustina Wisky has worked with our Company since it was founded in Company’s performance in 2014. During the year ended December 31, 2015, November 2002, and has served as our Director of People since 2012. Mrs. an amount of US$1.4 million, in the aggregate, was also accrued or paid for Wisky is a public accountant, and also holds a degree in human resources from discretionary bonus payments granted to the Company’s executive senior the Universidad Austral-IAE. She has 15 years of experience in the oil industry. management based on the Company’s performance in 2014. Recipients of Before joining our company, Mrs. Wisky worked at AES Gener and such bonuses were given the opportunity to receive their bonus payments in PricewaterhouseCoopers. shares, cash or a combination of both. Gerald E. O’Shaughnessy, James F. Park Guillermo Portnoi has worked with our Company since June 2006 and has been our Director of Business Management since May 2015. He previously Executive Director Contracts and Pedro Aylwin are our executive directors. served as our Director of Administration and Finance. Mr. Portnoi is a public It is our current policy that executive directors enter into indefinite term accountant and holds an MBA from Universidad Austral-IAE. He has more than contracts with the Company that may be terminated at any time by either 11 years of experience in the oil industry. Before joining our company, Mr. party subject to certain notice requirements. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers, where he counted several major oil companies as his clients. Gerald E. O’Shaughnessy has entered into a service contract with the Company Pablo Ducci has served as our Director of Capital Markets since 2012. Mr. Ducci has entered into a service contract with the Company to act as Chief Executive holds a bachelor’s degree in science and economics from Pontifical Catholic Officer at an annual salary of US$450,000. The payment of a bonus to Mr. to act as Executive Chairman at an annual salary of US$200,000. James F. Park GeoPark 145 O’Shaughnessy or Mr. Park is at our discretion. They each also received equity The following chart summarizes payments made to our non-executive directors awards described below under “Equity Incentive Compensation.” Our for the year ended December 31, 2015. agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that restrict them, for a period of 12 months following termination of employment, from soliciting senior employees of the Company and, for a period of six months following a termination of employment, from competing with the Company. Pedro Aylwin, who was appointed as an executive director in July 2013, has entered into a service contract with the Company to act as Director of Legal and Governance, and as such has decided to forego his director fees. He instead received in 2015 a salary of approximately US$317,000 and bonus of US$60,000 for his services as a member of senior management. The following cart summarizes payments made to our executive directors for the year ended December 31,2015: Executive Director Executive Directors’ Fees Gerald E. O’Shaughnessy James F. Park US$200,000 US$450,000 Cash payment Bonus US$75,000 US$325,000 Non-Executive Director Juan Cristóbal Pavez(2) Peter Ryalls(3) Carlos Gulisano(4) Steven J. Quamme(5) Robert Bedingfield(6) Non-Executive Directors’ Fees in US$ 99,000 108,000 99,000 33,322 70,000 Fees paid in Common Shares (in US$)(1) 90,029 90,029 90,029 30,885 70,025 (1) The numbers in this column are equal to 83,882 Common Shares (which amount equals to US$370,997). Of this amount of shares, 8,285 shares were not issued in 2015. (2) Compensation Committee Chairman and Member of Audit Committee. (3) Technical Committee Chairman, Member of Audit Committee and Member of Compensation Committee. (4) Nomination Committee Chairman and Member of Technical Committee. (5) Audit Committee Chairman and Member of Compensation Committee until resignation in 2015. (6) Audit Committee Chairman since March 2015 Bonus payments above were approved by the Compensation Committee in September 2015 and reflect awards for previous years’ performance including Pension and retirement benefits the discretionary bonus payments made based on our performance in 2014. As We do not maintain any defined benefit pension plans or any other retirement part of our cost reduction efforts, executive fees for the first semester of 2015 programs for our employees or directors. have been voluntarily reduced by 20%. Non-Executive Director Contracts Equity Incentive Compensation The current annual fees paid to our non-executive Directors correspond to Performance-Based Employee Long-Term Incentive Program US$80,000 to be settled in cash and US$100,000 to be settled in stock, paid In November 2007, our shareholders voted to authorize the board of directors quarterly in equal installments. In the event that a non-executive Director serves to use up to a maximum of 12% of our issued share capital for the purposes of as Chairman of any Board Committees, an additional annual fee of US$20,000 granting equity awards to our employees and other service providers. The applies. A Director who serves as a member of any Board Committees receives an shareholders also authorized the board of directors to adopt programs for this annual fee of US$10,000. Total payment due shall be calculated on an aggregate purpose and to determine specific conditions and broadly defined guidelines basis for Directors serving in more than one Committee. The Chairman fee is not for such programs. Pursuant to this authorization, we established the Stock added to the member’s fee while serving for the same Committee. Payments of Awards Plan and the Value Creation Plan. Chairmen and Committee members’ fees are made quarterly in arrears and settled in cash only. As part of our cost reduction efforts, non-executive fees for Stock Awards Plan the first semester of 2015 have been voluntarily reduced by 20%. The purpose of the Stock Awards Plan is to align the interests of our management, employees and key advisors with those of shareholders. Under the Stock Awards Plan, the board of directors, or its designee, may award options or performance shares. An option confers the right to acquire a specified number of common shares of the Company at an exercise price equal to the par value of the common shares subject to such an option. A performance share confers a conditional right to acquire a specified number of common shares for zero or nominal consideration, subject to the achievement of performance conditions and other vesting terms. 146 GeoPark 20F On December 17, 2014, we registered 3,435,600 shares with the U.S. SEC for have vested and been paid in common shares 50% on December 31, 2015, and shares to be issued under the Stock Awards Plan. The following table sets forth the remaining 50% on December 31, 2016. Notwithstanding the foregoing, the the common share awards granted to our executive directors, management total number of common shares granted pursuant to this plan would not have and key employees under the Stock Awards Plan commencing in 2008 exceeded 5% of the issued share capital of the Company. Additionally, the through March 2016. Number of underlying common shares outstanding 976,211(1) 817,600(1) 478,000(1) 720,000(2) 379,500(3) 417,000(4) 500,000 share price (and number of common shares outstanding) used to calculate if the market capitalization threshold had been met would have been subject to Grant date Vesting Expiration adjustment for any stock splits. date date 12/15/2008 12/15/2012 12/15/2018 The performance conditions of the VCP awards were not achieved. On 12/15/2010 12/15/2014 12/15/2020 December 10th 2015, the Board of Directors approved a renewal of the VCP for 12/15/2011 12/15/2015 12/15/2021 a new period of three years, with new rewards granted on January 1, 2016. 11/23/2012 11/23/2015 11/23/2016 Under the current VCP, if as of December 31, 2018, our share price has 12/15/2012 12/15/2016 12/15/2022 increased by 12% or more per year adjusted for WTI according to the plan 6/30/2013 12/31/2015 12/31/2019 conditions, VCP participants will receive awards with an aggregate value equal 12/31/2014 12/31/2017 12/31/2022 to 10% of the excess above the market capitalization threshold generated by (1) Pedro Aylwin 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) This amount includes 50,000 common share awards that vested on October 31, 2014. (4) Vesting of these common share awards was subject to the achievement of certain minimum financial and operational targets during a performance this share price (assuming that the share capital of the Company had remained at the same level as applicable at the time of establishment of the VCP: 59,535,614 shares). The awards will vest and be paid in common shares 50% on December 31, 2018, and the remaining 50% on December 31, 2019. As in 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. Non-Executive Director Plan In August 2014, our board of directors adopted the Non-Executive Director Plan period that runs through 2015. As such conditions were not achieved as of the in order to grant shares to non-executive directors as part of their compensation vesting date, the corresponding shares were not issued. program for serving as directors. In accordance with the resolutions adopted by our board of directors on May 20, 2014, our non-executive directors are paid their Our executive directors, senior management and key employees who have quarterly fees in the form of equity awards granted under the Non-Executive received option awards or common share awards under the Stock Awards Plan Director Plan. Under the Non-Executive Director Plan, the compensation authorize the Company to deposit any common shares they have received under committee may award common shares, restricted share units and other this plan in our Employee Benefit Trust (“EBT”). The EBT is held to facilitate holdings share-based awards that may be denominated or payable in common shares or and dispositions of those common shares by the participants thereof. Under the factors that influence the value of common shares. The maximum number of terms of the EBT, each participant is entitled to receive any dividends we may pay common shares available for issuance under the Non-Executive Director Plan is which correspond to their common shares held by the trust, according to 180,000 common shares. The compensation committee has, as of March 31, 2016, instructions sent by the Company to the trust administrator. The trust provides awarded an aggregate amount of 141,128 common shares, which were that Mr. James F. Park is entitled to vote all the common shares held in the trust. immediately vested upon grant, under the Non-Executive Director Plan. Value Creation Plan Potential dilution resulting from Equity Incentive Compensation Plans In July 2013, our compensation committee established the Value Creation Plan The percentage of total share capital that could be awarded to our directors, (“VCP”), to give our executive officers and key management members the management and key employees under the Stock Awards Plan and the opportunity to share in a percentage of the value created for shareholders in Non-Executive Director Plan described above would represent approximately excess of a pre-determined share price target at the end of a performance 12% of our issued common shares. In accordance with existing equity period. Under the VCP, if as of December 31, 2015, our share price (defined as compensation plans as of the date of this annual report, there are the average trading price of our common shares on the NYSE for the month of approximately 0.9 million shares that could vest until December 31, 2017, December 2015) had exceeded US$13.66, VCP participants would have representing approximately 1.47% of our current total issued share capital. received awards with an aggregate value equal to 10% of the excess above the market capitalization threshold generated by this share price (assuming that Share Repurchase Program the share capital of the Company had remained at the same level as applicable In December 2014, our board of directors approved a Share Repurchase at the time of establishment of the VCP: 43,495,585 shares). The awards would Program of up to US$10 million of our common shares, par value US$0.001 GeoPark 147 per share. The Share Repurchase Program began on December 19, 2014 and determined by our board of directors. In the future, our board of directors may expired at the close of business on August 18, 2015. The repurchased shares establish other committees to assist with its responsibilities. will be used to offset, in part, any expected dilution effects resulting from the Company’s equity incentive compensation plans, including grants under the Audit Committee Stock Awards Plan and the Non-Executive Director Plan. In the year ended The Audit Committee is composed of three directors: Mr. Peter Ryalls, Mr. Juan December 31, 2015, 0.37 million shares have been purchased under the Cristóbal Pavez and Mr. Robert Bedingfield (who currently serves as Chairman Share Repurchase Program. of the committee). We have determined that Mr. Peter Ryalls and Mr. Juan Cristóbal Pavez and Robert Bedingfield are independent, as such term is On April 5, 2016, we announced that we will resume our Share Repurchase defined under SEC rules applicable to foreign private issuers. Program of up to US$10 million of common shares, par value US$0.001 per share. The Share Repurchase Program will resume on April 6, 2016 and expire The Audit Committee’s responsibilities include: (a) approving our financial at the close of business on May 9, 2016, but it may be terminated prior to statements; (b) reviewing financial statements and formal announcements this date. The share repurchases may be made from time-to-time through relating to our performance; (c) assessing the independence, objectivity and open market transactions, block trades, privately negotiated transactions or effectiveness of our external auditors; (d) making recommendations for the otherwise, and are subject to market and business conditions, levels of appointment, re-appointment and removal of our external auditors and available liquidity, cash requirements for other purposes, regulatory, and approving their remuneration and terms of engagement; (e) implementing other relevant factors. The shares repurchased will be used to offset, in part, and monitoring policy on the engagement of external auditors supplying any expected dilution effects resulting from our employee incentive non-audit services to us; (f ) obtaining, at our expense, outside legal or other schemes, including grants under our Stock Award Plan and the Non- professional advice on any matters within its terms of reference and securing Executive Director Plan. C. Board practices Overview the attendance at its meetings of outsiders with relevant experience and expertise if it considers it necessary; and (g) reviewing our arrangements for our employees to raise concerns about possible wrongdoing in financial reporting or other matters and the procedures for handling such allegations, and ensuring that these arrangements allow proportionate and independent Our board of directors is responsible for establishing our strategic goals, investigation of such matters and appropriate follow-up action. ensuring that the necessary resources are in place to achieve these goals and reviewing our management and financial performance. Our board of directors Compensation Committee directs and monitors the company in accordance with a framework of controls, The Compensation Committee is composed of three directors. The current which enable risks to be assessed and managed through clear procedures, members of the compensation committee are Mr. Juan Cristóbal Pavez (who serves lines of responsibility and delegated authority. Our board of directors also has as Chairman of the committee) and Mr. Peter Ryalls. Currently there is a vacancy responsibility for establishing our core values and standards of business created by the resignation of Mr. Steve J. Quamme effective March 19, 2015. conduct and for ensuring that these, together with our obligations to our shareholders, are understood throughout the company. The Compensation Committee meets at least twice a year, and its specific Board composition responsibilities include: (a) recommending to the board of directors, the remuneration policy for the Chief Executive Officer, the Chairman, our Our bye-laws and board resolutions provide that the board of directors consist executive directors and other members of executive management; (b) of a minimum of three and a maximum of nine members. All of our directors reviewing the performance of our executive directors and members of were elected at our annual shareholders’ meeting held on June 30, 2015. Their executive management; and (c) reviewing all incentive compensation plans, term expires on the date of our next annual shareholders’ meeting, to be held equity-based plans, and all modifications to such plans as well as in 2016. The board of directors meets at least on a quarterly basis. administering and granting awards under all such plans and approving plan Committees of our board of directors payouts; and (d) reviewing and making recommendations to the Board with respect to the adoption or modification of executive officer and director share Our board of directors has established an Audit Committee, a Compensation ownership guidelines and monitor compliance with any adopted share Committee, a Nomination Committee, a Technical Committee and a Disclosure ownership guidelines. Committee. The composition and responsibilities of each committee are described below. Members serve on the Audit Committee for a period of three Nomination Committee years. For the Compensation and Nomination Committees, members serve for a The Nomination Committee is composed of three directors. The members of period of one year. For the Technical Committee and Disclosures Committee, the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. Carlos members serve on these committees until their resignation or until otherwise Gulisano (who serves as Chairman of the committee) and Mr. Pedro Aylwin. 148 GeoPark 20F 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, 2015 133 106 12 90 11 352 2014 133 197 12 100 14 456 2013 109 193 4 98 - 404 Technical Committee From time to time, we also utilize the services of independent contractors to The Technical Committee is composed of three directors along with the Chief perform various field and other services as needed. As of December 31, 2015, Operating Officer. The members of the Technical Committee are Mr. Peter 28 of our employees were represented by labor unions or covered by Ryalls (who serves as Chairman of the committee), Mr. Carlos Gulisano, Mr. collective bargaining agreements. We believe that relations with our James Park and Mr. Augusto Zubillaga. employees are satisfactory. The Technical Committee’s responsibilities include: (a) overseeing the technical studies and evaluations of the Company’s properties and proposals to acquire new properties and/or relinquish existing ones as well as reviewing project plans; (b) reviewing the Annual Reserve Report, the Company’s environmental programs and their effectiveness and the Company’s health and safety program and its effectiveness; and (c) providing a forum for ideas and solutions for the key technical people within the Company. Disclosure Committee The Disclosure Committee is composed of three nominated members, Mr. James Park, Mr. Andrés Ocampo and Mr. Pablo Ducci (who serves as Chairman of the committee), and certain other officers or managers per request. The Disclosure Committee’s responsibilities include (a) review and approval of filings with the SEC and press releases, (b) review of presentations to analysts, investors and rating agencies and (c) establishment of disclosure controls and procedures. Liability insurance We maintain liability insurance coverage for all of our directors and officers, the level of which is reviewed annually. D. Employees As of December 31, 2015, we had approximately 352 employees, of which 133 were located in Colombia, 106 were located in Chile, 90 were located in Argentina, 12 were located in Brazil and 11 in Peru. This represented a decrease of 23% from December 31, 2014, a decrease largely attributable to our Chilean operations. GeoPark 149 Major shareholders and related party transactions E. Share ownership Pavez. The common shares reflected as being held by Mr. Pavez include 44,227 As of March 8, 2016, members of our board of directors and our senior common shares held by him personally. management held as a group 20,411,330 of our common shares and 34% of our outstanding share capital. The following table shows the share ownership of each member of our board of directors and senior management as of March 8, 2016. A. Major shareholders ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS The following table presents the beneficial ownership of our common shares Shareholder Gerald E. O’Shaughnessy(1) James F. Park(2) Juan Cristóbal Pavez(3) Carlos Gulisano Pedro Aylwin Peter Ryalls Robert Bedingfield Augusto Zubillaga Alberto Matamoros Marcela Vaca Dimas Coelho Carlos Murut Salvador Minniti Jose Díaz Horacio Fontana Ruben Marconi Agustina Wisky Guillermo Portnoi Andrés Ocampo Pablo Ducci Common shares 7,894,496 7,891,269 2,922,031 151,196 220,859 80,352 40,364 * * * * * * * * * * * * * Sub-total senior management ownership of less than 1% Total 1,210,763 20,411,330 Percentage of as of March 8, 2016. outstanding common shares 13.2% 13.2% 4.9% 0.3% 0.4% 0.1% 0.1% * * * * * * * * * * * * * Shareholder Cartica Management LLC(1) Gerald E. O’Shaughnessy(2) James F. Park(3) IFC Equity Investments(4) Moneda A.F.I.(6) Juan Cristóbal Pavez(5) Other shareholders Total Common shares 9,690,972 7,894,496 7,891,269 3,456,594 3,184,650 2,922,031 24,988,973 60,028,985 Percentage of outstanding common shares 16.1% 13.2% 13.2% 5.8% 5.3% 4.9% 41.6% 100.0% (1) Held through certain private investment funds managed and controlled by Cartica Management, LLC. Mr. Steven Quamme and Mrs. Farida Khambata, partners at Cartica Management LLC, are deemed to have shared voting and investment power over such shares, on top of the shares personally held by each one of them. Mr. Quamme personally holds 20,236 shares and therefore is deemed to beneficially own an aggregate of 9,711,208 shares. Mrs. Farida Khambata personally holds 75,151 shares and therefore is deemed to beneficially own an aggregate of 9,766,123 shares. (2) Held directly and indirectly through GP Investments LLP, GPK Holdings LLC and The Globe Resources Group Inc., and other investment vehicles. 7,172,482 2.0% 34.0% of these common shares have been pledged pursuant to lending arrangements. (3) 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 * Indicates ownership of less than 1% of outstanding common shares. (1) Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, The Globe Resources Group Inc., and other investment not reflect the 1,464,265 common shares held as of March 8, 2016 in the employee benefit trust described under “Item 6. Directors, Senior Management and Employees-B. Compensation- Stock Awards Plan.” Although Mr. Park has vehicles. 7,172,482 of these common shares have been pledged pursuant to voting rights with respect to all the common shares held in the trust, Mr. Park lending arrangements. (2) 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 reflect the 1,464,265 common shares held as of March 8, 2016 in the EBT described under “Item 6. Directors, Senior Management and Employees-B. Compensation-Stock Awards Plan.” Although Mr. Park has voting rights with respect to all the common shares held in the trust, Mr. Park disclaims beneficial disclaims beneficial ownership over those common shares. 1,073,201 of these common shares have been pledged pursuant to lending arrangements. (4) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff. (5) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 44,227 ownership over those common shares. 1,073,201 of these common shares have been pledged pursuant to lending arrangements. (3) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal common shares held by him personally. (6) Held through various funds managed by Moneda A.F.I. (Administradora de Fondos de Inversión), an asset manager. 150 GeoPark 20F Principal shareholders do not have any different or special voting rights in LGI Colombia Agreements comparison to any other common shareholder. On December 18, 2012, we, Agencia, GeoPark Colombia and LGI entered into the LGI Colombia Shareholders’ Agreement and a subscription share According to our transfer agent, as of March 31, 2016, we had 35 shareholders agreement, pursuant to which LGI acquired a 20% interest in GeoPark registered in the U.S. As of December 31, 2015, there were a total of 16 Colombia SAS. Further, on January 8, 2014, following an internal corporate shareholders of record. Since some of the shares are held by nominees, the reorganization of our Colombian operations, GeoPark Colombia Coöperatie number of shareholders may not be representative of the number of U.A. and GeoPark Latin America entered into a new members’ agreement with beneficial owners. B. Related party transactions LGI (“LGI Colombia Members’ Agreement”), that sets out substantially 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 We have entered into the following transactions with related parties: Shareholders’ Agreement and the LGI Colombia Members’ Agreement LGI Chile Shareholders’ Agreements collectively as the LGI Colombia Agreements. The LGI Colombia Agreements provide that the board of GeoPark Colombia SAS will consist of four directors; In 2010, we formed a strategic partnership with LGI to acquire and develop as long as LGI holds at least 14% of GeoPark Colombia SAS, LGI has the right to jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired a elect one director and such director’s alternate, while the remaining directors, 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark TdF, and alternates, are elected by us. Additionally, the LGI Colombia Agreements for a total consideration of US$148.0 million, plus additional equity funding of require the consent of LGI or the LGI appointed director for GeoPark Colombia US$18.0 million through 2014. On May 20, 2011, in connection with LGI’s SAS to be able to take certain actions, including, among others: making any investment in GeoPark Chile, we and LGI entered into the LGI Chile decision to terminate or permanently or indefinitely suspend operations in or Shareholders’ Agreements, setting forth our and LGI’s respective rights and surrender our blocks in Colombia (other than as required under the terms of obligations in connection with LGI’s investment in our Chilean oil and gas the relevant concessions for such blocks); creating a security interest over our business. Specifically, the LGI Chile Shareholders’ Agreements provide that the blocks in Colombia; approving of GeoPark Colombia SAS’s annual budget and boards of each of GeoPark Chile and GeoPark TdF will consist of four directors; work programs and the mechanisms for funding any such budget or program; as long as LGI holds at least 5% of the voting shares of GeoPark Chile or entering into any borrowings other than those provided in an approved GeoPark TdF, as applicable, LGI has the right to elect one director and such budget or incurred in the ordinary course of business to finance working director’s alternate, while the remaining directors, and alternates, are elected capital needs; granting any guarantee or indemnity to secure liabilities of by us. Additionally, the agreements require the consent of LGI or its appointed parties other than those of our Colombian subsidiaries; changing the dividend, director in order for GeoPark Chile or GeoPark TdF, as applicable, to be able to voting or other rights that would give preference to or discriminate against take certain actions, including, among others: making any decision to the shareholders of GeoPark Colombia SAS; entering into certain related party terminate or permanently or indefinitely suspend operations in or surrender transactions; and disposing of any material assets other than those provided our blocks in Chile (other than as required under the terms of the relevant for in an approved budget and work program. The LGI Colombia Agreements CEOP for such blocks); selling our blocks in Chile to our affiliates; making any also provide that: (i) if either we or LGI decide to sell our respective shares in change to the dividend, voting or other rights that would give preference to or GeoPark Colombia SAS, the transferring shareholder must make an offer to sell discriminate against the shareholders of these companies; entering into those shares to the other shareholder before selling those shares to a third certain related party transactions; and creating a security interest over our party; and (ii) any sale to a third party is subject to tag-along and drag-along blocks in Chile (other than in connection with a financing that benefits our rights, and the non-transferring shareholder has the right to object to a sale to Chilean subsidiaries). The LGI Chile Shareholders’ Agreements also provide the third-party if it considers such third-party to be not of a good reputation that: (i) if LGI or either Agencia or GeoPark Chile decides to sell its shares in or one of our direct competitors. We and LGI also agreed to vote our common GeoPark Chile or GeoPark TdF, as applicable, the transferring shareholder must shares or otherwise cause GeoPark Colombia to declare dividends only after make an offer to sell those shares to the other shareholder before selling them allowing for retentions for approved work programs and budgets, capital to a third party; and (ii) any sale to a third party is subject to tag-along and adequacy and tied surplus requirements of GeoPark Colombia, working capital drag-along rights, and the non-transferring shareholder has the right to object requirements, banking covenants associated with any loan entered into by to a sale to the third-party if it considers such third-party to be not of a good GeoPark Colombia or our other Colombian subsidiaries and operational reputation or one of our direct competitors. We and LGI also agreed to vote requirements. See “Item 4. Information on the Company-B. Business overview- our common shares or otherwise cause GeoPark Chile or GeoPark TdF, as Significant agreements-Agreements with LGI-LGI Colombia Agreements.” applicable, to declare dividends only after allowing for retentions to meet anticipated future investments, costs and obligations. See “Item 4. Information on the Company-B. Business overview-Significant agreements-Agreements with LGI-LGI Chile Shareholders’ Agreements.” GeoPark 151 IFC Subscription and Shareholders’ Agreement See “Item 6. Directors, Senior Management and Employees-B. Compensation- On February 7, 2006, in order to finance the exploration, development and Executive compensation-Executive Directors’ Contracts.” exploitation of our blocks in Chile and Argentina and the acquisition of additional exploration, development and exploitation blocks in Latin America, For further information relating to our related party transactions and balances we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead Investors, outstanding as of December 31, 2015, 2014 and 2013, please see Note 32 to entered into an agreement (“IFC Subscription and Shareholders’ Agreement”), our Consolidated Financial Statements. pursuant to which IFC agreed to subscribe and pay for 2,507,161 of our common shares, representing approximately 10.5% of our then-outstanding C. Interests of Experts and Counsel common shares, at an aggregate subscription price of US$10.0 million (or Not applicable. approximately US$3.99 per common share). We agreed, for so long as IFC is a shareholder in the company, among other ITEM 8. FINANCIAL INFORMATION things, to: ensure that our operations are in compliance with certain environmental and social guidelines; appoint and maintain a technically qualified A. Consolidated statements and other financial information individual to be responsible for the environmental and social management of our activities; maintain certain forms of insurance coverage, including coverage Financial statements for public liability and director’s and officer’s liability reasonably acceptable to See “Item 18. Financial Statements,” which contains our audited financial IFC, and in respect of certain of our operations; not undertake certain prohibited statements prepared in accordance with IFRS. activities; and ensure that no prohibited payments are made by us or on our or the Lead Investors’ behalf, in respect of our operations. Legal proceedings We also agreed to provide to IFC, within 30 days of the end of the first half of the proceedings that arise in the normal course of business, including year, copies of our unaudited consolidated financial statements for the period employment, commercial, environmental, safety and health matters. For (prepared under IFRS), a report on our capital expenditures for the period, a example, from time to time, we receive notice of environmental, health and comprehensive report on the progress of the exploration, development and safety violations. It is not presently possible to determine whether any such exploitation of our blocks in Latin America and a statement of all related party matters will have a material adverse effect on our consolidated financial From time to time, we may be subject to various lawsuits, claims and transactions during the period, with a certification by a company officer that position and results of operations. these were on an arm’s-length basis; within 90 days of the end of our fiscal year, copies of our audited consolidated financial statements for the year (prepared In Brazil, GeoPark Brasil is a party to a class action filed by the Federal under IFRS), a management letter from our auditors in respect of our financial Prosecutor’s Office regarding a concession agreement of exploratory Block control procedures, accounting and management information systems and any PN-T-597, which the ANP initially awarded GeoPark Brasil in the 12th oil and gas litigation, an annual monitoring report confirming compliance with national or bidding round held in November 2013. The Brazilian Federal Court issued an local requirements and the environmental and social requirements mandated injunction against the ANP and GeoPark Brasil in December 2013 that by the agreement, a report indicating any payments in the year to any prohibited GeoPark Brasil’s execution of the concession agreement until the governmental authority in connection with the documents governing our ANP conducted studies on whether drilling for unconventional resources would Chilean and Argentine blocks and certificates of insurance, with a certificate of contaminate the dams and aquifers in the region. On July 17, 2015, GeoPark our insurer confirming that effectiveness of our policies and payment of all Brasil, at the instruction of the ANP, signed the concession agreement, which applicable premiums; within 45 days before each fiscal year begins, a proposed included a clause prohibiting GeoPark Brasil from conducting unconventional annual business plan and budget for the upcoming year; within 3 days after its exploration activity in the area. Despite the clause containing the prohibition, occurrence, notification of any incident that had or may reasonably be expected the judge in the case concluded that the concession agreement should not be to have an adverse effect on the environment, health or safety; copies of notices, executed. Thus, GeoPark Brasil requested that the ANP comply with the decision reports or other communications between us and our board of directors or and annul the concession agreement, which the ANP´s Board did on October 9, shareholders; and, within five days of receipt thereof, copies of any reports, 2015. The annulment reverted the status of all parties to the status quo ante , correspondence, documentation or notices from any third-party, governmental which maintains GeoPark Brasil’s right to the block. authority or state-owned company that could reasonably be expected to materially impact our operations. Mr. O’Shaughnessy and Mr. Park have also Dividends and dividend policy agreed to procure that shareholders holding 51% of our common shares cause Holders of common shares will be entitled to receive dividends, if any, paid on us to comply with the covenants above. the common shares. Executive Directors’ Service Agreements We have never declared or paid any cash dividends on our common shares. We We have entered into service contracts with certain of our executive directors. intend to retain all of our future earnings, if any, generated by our operations 152 GeoPark 20F for the development and growth of our business. Accordingly, we do not Our common shares have been listed on the NYSE under the symbol “GPRK” expect to pay cash dividends on our common shares in the foreseeable future. since February 7, 2014. They were previously listed on the AIM under the Because we are a holding company with no direct operations, we will only be symbol “GPK” until February 19, 2014, and, from 2009 to 2015 had been able to pay dividends from our available cash on hand and any funds we admitted to trade on the Santiago Offshore Stock Exchange ( Bolsa Offshore receive from our subsidiaries. The terms of our indebtedness may restrict us de la Bolsa de Comercio de Santiago ). from paying dividends. Mainly resulting from the impact of the decline in oil prices, we have recorded accumulated losses amounting to US$208.4 million The table below presents, for the periods indicated, the annual, quarterly and as of December 31, 2015, which further limits our ability to pay dividends in monthly high and low closing prices (in US$) of our common shares on the NYSE. the foreseeable future. Under the Bermuda Companies Act, we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than our Common shares Average daily trading volume High Low (US$ per share) (in shares) liabilities. We do not presently have any reasonable grounds for believing Annual price history that, if we were to declare or pay a dividend on our common shares 2014 (from February 7 outstanding, we would thereafter be unable to pay our liabilities as they through December 31, 2014) became due or that the realizable value of our assets would thereafter be 2015 less than our liabilities. 2016 (through April 8, 2016 Quarterly price history Additionally, any decision to pay dividends in the future, and the amount of 1st Quarter 2015 any distributions, is at the discretion of our board of directors and our 2nd Quarter 2015 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 3rd Quarter 2015 4th Quarter 2015 1st Quarter 2016 common shares-We have never declared or paid, and do not intend to pay in 2nd Quarter 2016 the foreseeable future, cash dividends on our common shares, and, (through April 8, 2016) consequently, your only opportunity to achieve a return on your investment Monthly price history is if the price of our stock appreciates” and “-We are a holding company November 2015 dependent upon dividends from our subsidiaries, which may be limited by December 2015 law and by contract from making distributions to us, which would affect our January 2016 financial condition, including the ability to pay dividends on the common February 2016 shares,” as well as “Item 10. Additional Information-B. Memorandum of March 2016 association and bye-laws.” April 2016 (through April 8, 2016) 11.00 5.59 3.60 5.48 5.59 4.69 3.54 3.60 2.93 3.54 3.44 3.60 3.28 3.11 2.93 4.92 2.70 2.55 3.60 4.00 2.87 2.70 2.60 2.55 3.05 2.70 2.60 2.88 2.62 2.55 47,795 23,838 6.341 42,734 23,385 22,471 7,374 6,736 3.575 5,614 8,216 10,085 3,602 6,403 3.575 B. Significant changes A discussion of the significant changes in our business can be found under “Item 4. Information on the Company-B. Business Overview.” ITEM 9. THE OFFER AND LISTING A. Offering and listing details Not applicable. B. Plan of distribution Not applicable. C. Markets On February 6, 2014 we completed our initial public offering and listed our common shares on the NYSE. Source: NYSE Connect D. Selling shareholders Not applicable. E. Dilution Not applicable. F. Expenses of the issue Not applicable. GeoPark 153 ITEM 10. ADDITIONAL INFORMATION A. Share capital Not applicable. of the company on such terms and conditions as it may determine, subject to the terms of the bye-laws and any resolution of the shareholders to the contrary. Common shares Holders of our common shares are entitled to one vote per share on all matters B. Memorandum of association and bye-laws submitted to a vote of holders of common shares. Subject to preferences that The following description of our memorandum of association and may be applicable to any issued and outstanding preference shares, holders of bye-laws does not purport to be complete and is subject to, and qualified common shares are entitled to receive such dividends, if any, as may be by reference to, all of the provisions of our memorandum of association declared from time to time by our board of directors out of funds legally and bye-laws. General available for dividend payments. Holders of common shares have no redemption, sinking fund, conversion, exchange or other subscription rights. In the event of our liquidation, the holders of common shares are entitled to We are an exempted company with limited liability incorporated under the share equally and ratably in our assets, if any, remaining after the payment of laws of Bermuda with registration number 33273 from the Registrar of all of our debts and liabilities, subject to any liquidation preference on any Companies. The rights of our shareholders will be governed by Bermuda outstanding preference shares. law and by our memorandum of association and bye-laws. Bermuda company law differs in some material respects from the laws generally Board composition applicable to Delaware corporations. Below is a summary of some of those Our bye-laws provide that our board of directors will determine the maximum material differences. size of the board, provided that it shall be not be composed of fewer than three directors. The maximum number of directors currently allowed is nine directors Because the following statements are summaries, they do not discuss all aspects and our board of directors currently consists of seven directors. of Bermuda law that may be relevant to us and to our shareholders. Election and removal of directors Share capital and bye-laws Our bye-laws provide that our directors shall hold office for such term as the Our share capital consists of common shares only. Our authorized share shareholders shall determine or, in the absence of such determination, until the capital consists of 5,171,949,000 common shares of par value US$0.001 per next annual general meeting or until their successors are elected or appointed share. As of the date of this annual report, there are 60,028,985 common or their office is otherwise vacated. Directors whose term has expired may offer shares outstanding. All of our issued and outstanding common shares are themselves for re-election at each election of the directors. fully paid and non-assessable. We also have an employee incentive program, pursuant to which we have granted share awards to our senior Under our bye-laws, a director may be removed by a resolution adopted by 65% management and certain key employees. See “Item 6. Directors, Senior or more of the votes cast by shareholders who (being entitled to do so) vote in Management and Employees.” person or by proxy at any general meeting of the shareholders in accordance with the provisions of our bye-laws. Notice convened for the purpose of According to our bye-laws, if our share capital is divided into different removing the director, containing a statement of the intention to do so, must be classes of shares, the rights attached to any class (unless otherwise served on such director not less than 14 days before the meeting. provided by the terms of issue of the shares of that class) may, whether or not the Company is being wound-up, be varied with the consent in Any vacancy created by the removal of a director at a special general meeting writing of the holders of at least two-thirds of the issued shares of that may be filled at that meeting by the election of another director in his or her class or with the sanction of a resolution passed by a majority of the place or, in the absence of any such election, by the board of directors. Any votes cast at a separate general meeting of the holders of the shares of other vacancy, including a newly created directorship, may be filled by our the class at which meeting the necessary quorum shall be two persons at board of directors. least, in person or by proxy, holding or representing one-third of the issued shares of the class. The rights conferred upon the holders of the Proceedings of board of directors shares of any class issued with preferred or other rights shall not, unless Our bye-laws provide that our business shall be managed by or under the otherwise expressly provided by the terms of issue of the shares of that direction of our board of directors. Our board of directors may act by the class, be deemed to be varied by the creation or issue of further shares affirmative vote of a majority of the directors present at a meeting at which a ranking pari passu therewith. quorum is present. The quorum necessary for the transaction of business at meetings of the board of directors shall be the presence of a majority of the Our bye-laws give our board of directors the power to issue any unissued shares board of directors from time to time. Our bye-laws also provide that resolutions 154 GeoPark 20F unanimously signed by all directors are valid as if they had been passed at a Interested directors meeting of the board duly called and constituted. Pursuant to our bye-laws, a director shall declare the nature of his interest in any Duties of directors contract or arrangement with the company as required by the Bermuda Companies Act. A director so interested shall not, except in particular Under Bermuda common law, members of a board of directors owe a fiduciary circumstances set out in our bye-laws, be entitled to vote or be counted in the duty to the Company to act in good faith in their dealings with or on behalf of quorum at a meeting in relation to any resolution in which he has an interest, the company, and to exercise their powers and fulfill the duties of their office which is to his knowledge, a material interest (otherwise than by virtue of his honestly. This duty has the following essential elements: (1) a duty to act in interest in shares or debentures or other securities of or otherwise in or through good faith in the best interests of the company; (2) a duty not to make a the company). A director will be liable to us for any secret profit realized from the personal profit from opportunities that arise from the office of director; (3) a transaction. In contrast, under Delaware law, such a contract or arrangement is duty to avoid conflicts of interest; and (4) a duty to exercise powers for the voidable unless it is approved by a majority of disinterested directors or by a vote purpose for which such powers were intended. The Bermuda Companies Act of shareholders, in each case if the material facts as to the interested director’s also imposes a duty on directors of a Bermuda company, to act honestly and in relationship or interests are disclosed or are known to the disinterested directors or good faith, with a view to the best interests of the company, and to exercise the shareholders, or such contract or arrangement is fair to the corporation as of the care, diligence and skill that a reasonably prudent person would exercise in time it is approved or ratified. Additionally, such interested director could be held comparable circumstances. In addition, the Bermuda Companies Act imposes liable for a transaction in which such director derived an improper personal benefit. various duties on directors with respect to certain matters of management and administration of the company. Indemnification of directors and officers The Bermuda Companies Act provides that in any proceedings for negligence, directors and officers against any loss arising from or liability which by virtue of default, breach of duty or breach of trust against any director, if it appears to a any rule of law would otherwise be imposed on them in respect of any court that such officer is or may be liable in respect of the negligence, default, negligence, default, breach of duty or breach of trust except in cases where such breach of duty or breach of trust, but that he has acted honestly and reasonably, liability arises from fraud or dishonesty of which such director or officer may be Bermuda law provides generally that a Bermuda company may indemnify its and that, having regard to all the circumstances of the case, including those guilty in relation to the company. connected with his appointment, he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, Our bye-laws provide that we shall indemnify our officers and directors in either wholly or partly, from any liability on such terms as the court may think fit. respect of their actions and omissions, except in respect of their fraud or This provision has been interpreted to apply only to actions brought by or on dishonesty, or to recover any gain, personal profit or advantage to which such behalf of the company against the directors. director is not legally entitled, and (by incorporation of the provisions of the Bermuda Companies Act) that we may advance monies to our officers and By comparison, under Delaware law, the business and affairs of a corporation directors for costs, charges and expenses incurred by our officers and directors in are managed by or under the direction of its board of directors. In exercising defending any civil or criminal proceeding against them on the condition that their powers, directors are charged with a duty of care and a duty of loyalty. the officers and directors repay the monies if any allegation of fraud or The duty of care requires that directors act in an informed and deliberate dishonesty is proved against them provided, however, that, if the Bermuda manner and to inform themselves, prior to making a business decision, of all Companies Act requires, an advancement of expenses shall be made only upon relevant material information reasonably available to them. The duty of care delivery to the Company of an undertaking ,by or on behalf of such indemnitee, also requires that directors exercise care in overseeing the conduct of to repay all amounts so advanced if it shall ultimately be determined by final corporate employees. The duty of loyalty is the duty to act in good faith, not judicial decision from which there is no further right to appeal that such out of self-interest, and in a manner which the director reasonably believes to indemnitee is not entitled to be indemnified for such expenses under this be in the best interests of the shareholders. A party challenging the propriety Bye-law or otherwise. Our bye-laws provide that the company and the of a decision of a board of directors bears the burden of rebutting the shareholders waive all claims or rights of action that they might have, presumptions afforded to directors by the “business judgment rule.” If the individually or in right of the company, against any of the company’s directors or presumption is not rebutted, the business judgment rule attaches to protect officers for any act or failure to act in the performance of such director’s or the directors and their decisions. Where, however, the presumption is rebutted, officers’ duties, except with respect to any fraud or dishonesty, or to recover any the directors bear the burden of demonstrating the fairness of the relevant gain, personal profit or advantage to which such director is not legally entitled. transaction. Notwithstanding the foregoing, Delaware courts subject directors’ conduct to enhanced scrutiny in respect of defensive actions taken in Meetings of shareholders response to a threat to corporate control and approval of a transaction Under Bermuda law, a company is required to convene the annual general resulting in a sale of control of the corporation. meeting of shareholders each calendar year, unless the shareholders in a general GeoPark 155 meeting, elect to dispense with the holding of annual general meetings. Under companies amalgamate or merge or (b) two or more wholly-owned subsidiary Bermuda law and our bye-laws, a special general meeting of shareholders may companies of the same holding company amalgamate or merge. Under the be called by the board of directors and may be called upon the requisition of Bermuda Companies Act (save for such “short-form amalgamations”), unless a shareholders holding not less than 10% of the paid-up capital of the company company’s bye-laws provide otherwise, the approval of 75% of the shareholders carrying the right to vote at general meetings of shareholders. voting at a meeting is required to pass a resolution to approve the amalgamation or merger agreement, and the quorum for such meeting must Our bye-laws provide that, at any general meeting of the shareholders, the be two persons holding or representing more than one-third of the issued presence in person or by proxy of two or more shareholders representing in shares of the company. Our bye-laws provide that an amalgamation or merger excess of 50% of the total issued voting shares of the company shall constitute a will require the approval of our board of directors and of our shareholders by a quorum for the transaction of business unless the company only has one resolution adopted by 65% or more of the votes cast by shareholders who shareholder, in which case such shareholder shall constitute a quorum. Unless (being entitled to do so) vote in person or by proxy at any general meeting of otherwise required by law or by our bye-laws, shareholder action requires a the shareholders in accordance with the provisions of the bye-laws. Under resolution adopted by a majority of votes cast by shareholders at a general Bermuda law, in the event of an amalgamation or merger of a Bermuda meeting at which a quorum is present. Shareholder proposals company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of Under Bermuda law, shareholders holding at least 5% of the total voting rights of the notice of the shareholders meeting, apply to the Supreme Court of all the shareholders having at the date of the requisition a right to vote at the Bermuda to appraise the value of those shares. meeting to which the requisition relates or any group composed of at least 100 or more shareholders may require a proposal to be submitted to an annual Under the Bermuda Companies Act, we are not required to seek the approval of general meeting of shareholders. our shareholders for the sale of all or substantially all of our assets. However, Bermuda courts will view decisions of the English courts as highly persuasive Under our bye-laws, any shareholders wishing to nominate a person for election and English authorities suggest that such sales do require shareholder approval. as a director or propose business to be transacted at a meeting of shareholders Our bye-laws provide that the directors shall manage the business of the must provide (among other things) advance notice, as set out in our bye-laws. Company and may exercise all such powers as are not, by the Bermuda Shareholders may only propose a person for election as a director at an annual Companies Act or by these Bye-laws, required to be exercised by the Company in general meeting. Shareholder action by written consent general meeting and may pay all expenses incurred in promoting and incorporating the company and may exercise all the powers of the Company including, but not by way of limitation, the power to borrow money and to Our bye-laws provide that, except for the removal of auditors and directors, any mortgage or charge all or any part of the undertaking property and assets actions which shareholders may take at a general meeting of shareholders may (present and future) and uncalled capital of the Company and to issue be taken by the shareholders through the unanimous written consent of the debentures and other securities, whether outright or as collateral security for any shareholders who would be entitled to vote on the matter at the general debt, liability or obligation of the Company or any other persons. meeting. Amendment of memorandum of association and bye-laws four months of the offer, the holders of not less than 90% of the shares not Our memorandum of association and bye-laws may be amended with the owned by the offeror, its subsidiaries or their nominees accept such offer, the approval of a majority of our board of directors and by a resolution by a majority offeror may by notice require the non-tendering shareholders to transfer their of the votes cast by shareholders who (being entitled to do so) vote in person or shares on the terms of the offer. Dissenting shareholders do not have express by proxy at any general meeting of the shareholders in accordance with the appraisal rights but are entitled to seek relief (within one month of the Under Bermuda law, where an offer is made for shares of a company and, within provisions of the bye-laws. Business combinations compulsory acquisition notice) from the court, which has power to make such orders as it thinks fit. Additionally, where one or more parties hold not less than 95% of the shares of a company, such parties may, pursuant to a notice given to A Bermuda company may engage in a business combination pursuant to a the remaining shareholders, acquire the shares of such remaining shareholders. tender offer, amalgamation, merger or sale of assets. The amalgamation or Dissenting shareholders have a right to apply to the court for appraisal of the merger of a Bermuda company with another company generally requires the value of their shares within one month of the compulsory acquisition notice. If a amalgamation or merger agreement to be approved by the company’s board dissenting shareholder is successful in obtaining a higher valuation, that of directors and by its shareholders. Shareholder approval is not required where valuation must be paid to all shareholders being squeezed out or the purchaser (a) a holding company and one or more of its wholly-owned subsidiary may cancel the purchase notice sent. 156 GeoPark 20F Dividends and repurchase of shares Bermuda Companies Act, establish a branch register outside of Bermuda. Pursuant to our bye-laws, our board of directors has the authority to declare Bermuda law does not, however, provide a general right for shareholders to dividends and authorize the repurchase of shares subject to applicable law. inspect or obtain copies of any other corporate records. Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the Registrar or transfer agent payment be, unable to pay its liabilities as they become due or the realizable A register of holders of the common shares is maintained by Coson Corporate value of its assets would thereby be less than its liabilities. Under Bermuda law, a Services Limited in Bermuda, and a branch register is maintained in the United company cannot purchase its own shares if there are reasonable grounds for States by Computershare Trust Company, N.A., who serves as branch registrar believing that the company is, or after the repurchase would be, unable to pay its and transfer agent. liabilities as they become due. Enforcement of Judgments Shareholder suits We are incorporated as an exempted company with limited liability under the Class actions and derivative actions are generally not available to shareholders laws of Bermuda, and substantially all of our assets are located in Colombia, under Bermuda law. The Bermuda courts, however, would ordinarily be expected Chile, Brazil and to a lesser extent in Argentina. In addition, most of our directors to permit a shareholder to commence an action in the name of a company to and executive officers reside outside the United States, and all or a substantial remedy a wrong to the company where the act complained of is alleged to be portion of the assets of such persons are located outside the United States. As a beyond the corporate power of the company or illegal, or would result in the result, it may be difficult for investors to effect service of process on those violation of the company’s memorandum of association or bye-laws. persons in the United States or to enforce in the United States judgments Furthermore, consideration would be given by a Bermuda court to acts that are obtained in U.S. courts against us or those persons based on the civil liability alleged to constitute a fraud against the minority shareholders or where an act provisions of the U.S. securities laws. requires the approval of a greater percentage of the company’s shareholders than that which actually approved it. There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and When the affairs of a company are being conducted in a manner which is commercial matters. As a result, whether a U.S. judgment would be oppressive or prejudicial to the interests of some part of the shareholders, one or enforceable in Bermuda against us or our directors and officers depends on more shareholders may apply under the Bermuda Companies Act for an order of whether the U.S. court that entered the judgment is recognized by the the Supreme Court of Bermuda, which may make such order as it sees fit, Bermuda court as having jurisdiction over us or our directors and officers, as including an order regulating the conduct of the company’s affairs in the future determined by reference to Bermuda conflict of law rules and the judgment or ordering the purchase of the shares of any shareholders by other shareholders is not contrary to public policy in Bermuda, has not been obtained by fraud or by the company. in proceedings contrary to natural justice and is not based on an error in Bermuda law. A judgment debt from a U.S. court that is final and for a sum Our bye-laws contain a provision through which we and our shareholders waive certain based on U.S. federal securities laws will not be enforceable in any claim or right of action that we or they have, both individually and on our Bermuda unless the judgment debtor had submitted to the jurisdiction of behalf, against any director or officer in relation to any action or failure to take the U.S. court, and the issue of submission and jurisdiction is a matter of action by such director or officer, including the breach of any fiduciary duty, Bermuda (not U.S.) law. except in respect of any fraud or dishonesty of such director or officer. An action brought pursuant to a public or penal law, the purpose of which is Access to books and records and dissemination of information the enforcement of a sanction, power or right at the instance of the state in its Members of the general public have a right to inspect the public documents of a sovereign capacity, may not be entertained by a Bermuda court. Certain company available at the office of the Registrar of Companies in Bermuda. These remedies available under the laws of U.S. jurisdictions, including certain documents include the company’s memorandum of association and any remedies under U.S. federal securities laws, may not be available under amendments thereto. The shareholders have the additional right to inspect the Bermuda law or enforceable in a Bermuda court, as they may be contrary to bye-laws of the company, minutes of general meetings of shareholders and the Bermuda public policy. Further, no claim may be brought in Bermuda against company’s audited financial statements. The company’s audited financial us or our directors and officers in the first instance for violations of U.S. federal statements must be presented at the annual general meeting of shareholders, securities laws because these laws have no extraterritorial jurisdiction under unless the board and all the shareholders agree to the waiving of the audited Bermuda law and do not have force of law in Bermuda. A Bermuda court may, financials. The company’s share register is open to inspection by shareholders however, impose civil liability on us or our directors and officers if the facts and by members of the general public without charge. A company is required to alleged in a complaint constitute or give rise to a cause of action under maintain its share register in Bermuda but may, subject to the provisions of the Bermuda law. However, section 281 of the Bermuda Companies Act allows a GeoPark 157 Bermuda court, in certain circumstances, to relieve officers and directors of the judgment being final under the laws of the country in which it was rendered. Bermuda companies of liability for acts of negligence, breach of duty or trust Nonetheless, we have been advised by our Chilean counsel that there is doubt as or other defaults. to the enforceability in original actions in Chilean courts of liabilities predicated solely upon U.S. federal or state securities laws. Section 98 of the Bermuda Companies Act provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability C. Material contracts which by virtue of any rule of law would otherwise be imposed on them in See “Item 4. Information on the Company-B. Business overview-Significant respect of any negligence, default, breach of duty or breach of trust, except in agreements.” cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further D. Exchange controls provides that a Bermuda company may indemnify its directors, officers and Not applicable. auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favor or in which E. Taxation they are acquitted or granted relief by the Supreme Court of Bermuda pursuant The following summary contains a description of certain Bermudian, U.S. federal to Section 281 of the Bermuda Companies Act. income, and Chilean tax consequences of the acquisition, ownership and disposition of our common shares. The summary is based upon the tax laws of Our bye-laws contain provisions whereby we and our shareholders waive any Bermuda, the United States, and Chile, and regulations thereunder as of the date claim or right of action that we have, both individually and on our behalf, against hereof, which are subject to change. 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 such director or Bermuda tax consideration officer. We may also indemnify our directors and officers in their capacity as At the date of this annual report, there is no Bermuda income or profits tax, directors and officers for any loss arising or liability attaching to them by virtue withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance of any rule of law in respect of any negligence, default, breach of trust of which a tax payable by us or by our shareholders in respect of our common shares. We director or officer may be guilty in relation to the company other than in respect have obtained an assurance from the Minister of Finance of Bermuda under the of his own fraud or dishonesty. We have entered into customary indemnification Exempted Undertakings Tax Protection Act 1966 that, in the event that any agreements with our directors. legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the No treaty exists between the United States and Chile for the reciprocal nature of estate duty or inheritance tax, such tax shall not, until March 31, 2035, recognition and enforcement of foreign judgments. Chilean courts, however, be applicable to us or to any of our operations or to our common shares, have enforced valid and conclusive judgments for the payment of money debentures or other obligations except insofar as such tax applies to persons rendered by competent U.S. courts by virtue of the legal principles of reciprocity ordinarily resident in Bermuda or is payable by us in respect of real property and comity, subject to review in Chile of the U.S. judgment in order to ascertain owned or leased by us in Bermuda. We pay annual Bermuda government fees. whether certain basic principles of due process and public policy have been respected, without retrial or review of the merits of the subject matter. If a U.S. Material U.S. federal income tax considerations court grants a final judgment, enforceability of this judgment in Chile will be The following is a description of the material U.S. federal income tax subject to obtaining the relevant exequatur (i.e., recognition and enforcement of consequences to U.S. Holders (as defined below) of owning and disposing of our the foreign judgment) according to Chilean civil procedure law in effect at that common shares. This discussion is not a comprehensive description of all tax time, and depending on certain factors (the satisfaction or non-satisfaction of considerations that may be relevant to a particular person’s decision to hold our which would be determined by the Supreme Court of Chile). Currently, the most common shares. This discussion applies only to a U.S. Holder that holds our important of such factors are: the existence of reciprocity (if it can be proved that common shares as capital assets for tax purposes. In addition, it does not there is no reciprocity in the recognition and enforcement of the foreign describe all of the tax consequences that may be relevant in light of the U.S. judgment between the United States and Chile, that judgment would not be Holder’s particular circumstances, including alternative minimum tax and enforced in Chile); the absence of any conflict between the foreign judgment Medicare contribution tax consequences and differing tax consequences and Chilean laws (excluding for this purpose the laws of civil procedure) and applicable to a U.S. Holder subject to special rules, such as: Chilean public policy; the absence of a conflicting judgment by a Chilean court • certain financial institutions; relating to the same parties and arising from the same facts and circumstances; • a dealer or trader in securities who uses a mark-to-market method of tax the Chilean court’s determination that the U.S. courts had jurisdiction, that accounting; process was appropriately served on the defendant and that the defendant was • a person holding common shares as part of a straddle, wash sale or conversion afforded a real opportunity to appear before the court and defend its case; and transaction or entering into a constructive sale with respect to the common shares; 158 GeoPark 20F • a person whose functional currency for U.S. federal income tax purposes is such as the NYSE where our common shares are traded. Non-corporate U.S. not the US$; Holders should consult their tax advisers to determine whether the favorable rate • a partnership or other entities classified as partnerships for U.S. federal will apply to dividends they receive and whether they are subject to any special income tax purposes; rules that limit their ability to be taxed at this favorable rate. • a tax-exempt entity, including an “individual retirement account” or “Roth IRA;” • a person that owns or is deemed to own 10% or more of our voting stock; A dividend generally will be included in a U.S. Holder’s income when received, • a person who acquired our shares pursuant to the exercise of an employee will be treated as foreign-source income to U.S. Holders and will not be eligible stock option or otherwise as compensation; or for the dividends-received deduction generally available to U.S. corporations • a person holding common shares in connection with a trade or business under the Code with respect to dividends paid by domestic corporations. conducted outside of the United States. Sale or other taxable disposition of common shares If an entity that is classified as a partnership for U.S. federal income tax purposes Gain or loss realized on the sale or other taxable disposition of our common holds common shares, the U.S. federal income tax treatment of a partner will shares will be capital gain or loss, and will be long-term capital gain or loss if the generally depend on the status of the partner and the activities of the U.S. Holder held our common shares for more than one year. Long-term capital partnership. Partnerships holding common shares and partners in such gain of a non-corporate U.S. Holder is generally taxed at preferential rates. The partnerships should consult their tax advisers as to the particular U.S. federal deductibility of capital losses is subject to limitations. The amount of the gain or income tax consequences of their investment in our common shares. loss will equal the difference between the U.S. Holder’s tax basis in the common shares disposed of and the amount realized on the disposition. If a Chilean tax is This discussion is based on the Internal Revenue Code of 1986, as amended withheld on the sale or disposition of the common shares, a U.S. Holder’s amount (“Code”), administrative pronouncements, judicial decisions, and final, temporary realized will include the gross amount of the proceeds of the sale or disposition and proposed Treasury regulations, all as of the date hereof, any of which is before deduction of the Chilean tax. See “-Chilean tax on transfers of shares” for a subject to change, possibly with retroactive effect. U.S. Holders should consult description of when a disposition may be subject to taxation by Chile. This gain their tax advisers concerning the U.S. federal, state, local and foreign tax or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. consequences of owning and disposing of our common shares in their particular U.S. Holders should consult their tax advisers as to whether the Chilean tax on circumstances. gains may be creditable against the U.S. Holder’s U.S. federal income tax on A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal income tax purposes that is: Passive foreign investment company rules foreign-source income from other sources. • a citizen or individual resident of the United States; We believe that we were not a “passive foreign investment company,” or PFIC, for • a corporation, or other entity taxable as a corporation, created or organized in U.S. federal income tax purposes for 2015, and we do not expect to be a PFIC in or under the laws of the United States, any state therein or the District of the foreseeable future. However, because the composition of our income and Columbia; or assets will vary over time, there can be no assurance that we will not be a PFIC for • an estate or trust the income of which is subject to U.S. federal income any taxable year. The determination of whether we are a PFIC is made annually taxation regardless of its source. and is based upon the composition of our income and assets (including the income and assets of, among others, entities in which we hold at least a 25% This discussion assumes that we are not, and will not become, a passive foreign interest), and the nature of our activities. investment company, as described below. Taxation of distributions If we were a PFIC for any taxable year during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition Distributions paid on our common shares, other than certain pro rata (including certain pledges) of our common shares would generally be distributions of common shares, will generally be treated as dividends to the allocated ratably over the U.S. Holder’s holding period for the common shares. extent paid out of our current or accumulated earnings and profits (as The amounts allocated to the taxable year of the sale or other disposition and determined under U.S. federal income tax principles). Because we do not to any year before we became a PFIC would be taxed as ordinary income. The maintain calculations of our earnings and profits under U.S. federal income tax amount allocated to each other taxable year would be subject to tax at the principles, it is expected that distributions will generally be reported to U.S. highest rate in effect for individuals or corporations for that year, as Holders as dividends. Dividends paid by qualified foreign corporations to certain appropriate, and an interest charge would be imposed on the tax on such non-corporate U.S. Holders may be taxable at favorable rates. A foreign amount. Further, to the extent that any distribution received by a U.S. Holder corporation is treated as a qualified foreign corporation with respect to dividends on its common shares exceeds 125% of the average of the annual distributions paid on stock that is readily tradable on a securities market in the United States, on the shares received during the preceding three years or the U.S. Holder’s GeoPark 159 holding period, whichever is shorter, that distribution would be subject to “Item 4. Information on the Company-B. Business overview-I ndustry and taxation in the same manner as gain, as described immediately above. Certain regulatory framework -Chile.” elections may be available that would result in alternative treatments (such as mark-to-market treatment) of our common shares. U.S. Holders should consult As of December 31, 2015, our Chilean Assets represented more than UTA 210,000 their tax advisers to determine whether any of these elections would be and represent more than 20% of our market value. available and, if so, what the consequences of the alternative treatments would be in their particular circumstances. The 35% rate is calculated pursuant to one of the following methods, as determined by the seller: Information reporting and backup withholding • the sale price of the shares minus the acquisition cost of such shares, multiplied Payments of dividends and sales proceeds that are made within the United by the percentage or proportion of the part of the underlying Chilean Assets’ States or through certain U.S.-related financial intermediaries generally are fair market value (which assets are deemed to be “indirectly transferred” by subject to information reporting, and may be subject to backup withholding, virtue of the sale of shares) to the fair market value of the shares of the seller; or unless (1) the U.S. Holder is a corporation or other exempt recipient or (2) in • the portion of the sales price of the shares equal to the proportion of the fair the case of backup withholding, the U.S. Holder provides a correct taxpayer market value of the underlying Chilean Assets, minus the corresponding identification number and certifies that it is not subject to backup withholding. proportion in the tax cost of such Chilean Assets for the corresponding The amount of any backup withholding from a payment to a U.S. Holder will holding entity. be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely However, the seller may opt to be taxed as if the underlying Chilean Assets had furnished to the Internal Revenue Service. been sold directly in which case a different set of tax rules may apply. Chilean tax on transfers of shares The tax is payable by the seller of the shares; however, the buyer shall make a In September 2012, Article 10 of the Chilean Income Tax Law Decree Law No. provisional withholding unless the seller declares and pays the tax within the 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes on month following the sale, payment, remittance or it is credited into its account the indirect transfer of shares, equity rights, interests or other rights in the or is put at its disposal. Also, if the seller fails to declare and pay this tax, and the equity, control or profits of a Chilean entity as well as transfers of other assets buyer has not complied with its withholding obligations, the Chilean tax and property of permanent establishments or other businesses in Chile. The authority ( Servicio de Impuestos Internos ) may charge such tax directly to any 2014 tax reform introduces a measure which obliges the company from which of them. In addition, the Chilean tax authority may require us, the seller, the shares are transferred to pay taxes if the entity which undertakes the transfer buyer, or its representative in Chile, to file an affidavit with the information of shares fails to do so. necessary to assess this tax. The indirect transfer rules apply to sales of shares of an entity: Based on information available to us, (i) no Chilean resident holds 5% or more of • If such entity is an offshore holding company located in a black-listed tax our rights to equity, control or profits; or (ii) residents in black-listed jurisdictions haven jurisdiction as determined by Chilean tax law, or a black-listed hold 50% or more of our rights to equity, control or profits. Therefore, we do not jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean believe the indirect transfer rules will apply to transfers of our common shares, resident holds 5% or more of such entity, or such entity’s rights to equity, unless the shares or rights transferred represent 10% or more of the company control or profits, or 50% or more of such entity’s rights to equity or profits and the other conditions described above are met (considering dispositions by are held by residents in black-listed jurisdictions; or related persons and over the preceding 12-month period). • the shares or rights transferred represent 10% or more of the offshore holding company (considering dispositions by related persons and over the However, there can be no assurance that, at any time in the future, a Chilean preceding 12-month period) and the underlying Chilean Assets indirectly resident will not hold 5% or more of our rights to equity, control or profits or that transferred, in the proportion indirectly owned by the seller, (a) are valued in residents in black-listed jurisdictions will not hold 50% or more of our rights to an amount equal to or higher than UTA 210,000 (approximately US$200 equity, control or profits. If this were to occur, all sales of our common shares million) (adjusted by the Chilean inflation unit of reference) or (b) represent would be subject to the indirect transfer tax referred to above. 20% or more of the market value of the interest held by such seller in such offshore holding company. Our expectations regarding the indirect transfer rules are based on our understandings, analysis and interpretation of these enacted indirect transfer As a result of these rules, a capital gain tax of 35% will be applied by the Chilean rules, which are subject to additional interpretation and rule-making by the tax authorities to the sale of any of our common shares if either of the above Chilean authorities. As such, there is uncertainty relating to the application by alternative are met. This rate might be subject to change in the short term. See Chilean authorities of the indirect transfer rules on us. 160 GeoPark 20F See “Item 3. Key Information-D. Risk Factors-Risks related to our common D. American Depositary Shares shares-The transfer of our common shares may be subject to capital gains Not applicable. taxes pursuant to indirect transfer rules in Chile.” F. Dividends and paying agents Not applicable. G. Statement by experts Not applicable. H. Documents on display We are subject to the informational requirements of the Exchange Act. Accordingly, we are required to file reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. You may inspect and copy reports and other information filed with the SEC at the Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on 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 that contains reports and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. I. Subsidiary information Not applicable. ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to a variety of market risks, including commodity price risk, interest rate risk, currency risk and credit (counterparty and customer) risk. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates. For further information on our market risks, please see Note 3 to our Consolidated Financial Statements. ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES A. Debt securities Not applicable. B. Warrants and rights Not applicable. C. Other securities Not applicable. GeoPark 161 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 may HOLDERS AND USE OF PROCEEDS Not applicable. ITEM 15. CONTROLS AND PROCEDURES A. Disclosure Controls and Procedures 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, 2015, under the supervision and with the participation of Under the supervision and with the participation of our management, including our management, including our Chief Executive Officer and Chief Financial our Chief Executive Officer, our Chief Financial Officer, and our Director of Legal Officer, we performed an evaluation of the effectiveness of the design and and Governance, we conducted an evaluation of the effectiveness of our internal operation of our disclosure controls and procedures (as defined in Rule control over financial reporting as of December 31, 2015, based on the criteria 13a-15(e) under the Exchange Act). There are inherent limitations to the established in Internal Control - Integrated Framework of the Committee of effectiveness of any disclosure controls and procedures system, including the Sponsoring Organizations of the Treadway Commission (2013). possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable Based on this assessment, management believes that, as of December 31, 2015, assurance of achieving their control objectives. its internal control over financial reporting was effective based on those criteria. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer C. Attestation Report of the Registered Public Accounting Firm concluded that our disclosure controls and procedures are effective to provide Not applicable. reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is (1) recorded, processed, D. Changes in Internal Control over Financial Reporting summarized and reported within the time periods specified in the SEC’s rules There have been changes in our internal control over financial reporting during and forms and (2) accumulated and communicated to our management to the period covered by this annual report on Form 20-F that have materially allow timely decisions regarding required disclosures. affected our internal control over financial reporting. B. Management’s Annual Report on Internal Control over Financial In 2014, we started implementing a new enterprise resource planning system Reporting (“ERP”) with a view to make our operations more efficient, improving process Our management is responsible for establishing and maintaining an adequate management and decision-making, and strengthening our internal control internal control over financial reporting as defined in Rule 13a-15(f) under the system. As part of this process, in 2015 we have successfully undertaken the Exchange Act. implementation of this new ERP to our Colombian, Chilean, Brazilian and Argentinean operations to support its business processes. Our internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers, management and other personnel, to provide reasonable assurance regarding ITEM 16. RESERVED the reliability of financial reporting and the preparation of our financial statements for external reporting purposes, in accordance with generally ITEM 16A. Audit committee financial expert accepted accounting principles. These include those policies and procedures that: • pertain to the maintenance of records that, in reasonable detail, accurately We have determined that Mr. Peter Ryalls, Mr. Juan Cristóbal Pavez and Mr. Robert and fairly reflect transactions and dispositions of our assets; Bedingfield are independent, as such term is defined under SEC rules applicable 162 GeoPark 20F to foreign private issuers. In addition, Mr. Robert Bedingfield and Mr. Juan partners in the appointed firm are rotated in accordance with best practices. Cristobal Pavez are regarded as audit committee financial experts. Also, following our NYSE listing, the Audit Committee is required to pre- ITEM 16B. Code of Conduct approve the audit and non-audit fees and services 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. We have adopted a code of conduct applicable to the board of directors and all employees. Since its effective date on September 24, 2012, we have not waived All of the audit fees, audit-related fees and tax fees described in this item 16C compliance with or amended the code of conduct. have been approved by the Audit Committee. 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 fees Other fees paid Total Audit Fees 2015 2014 (in millions of US$) 0.56 0.13 - - 0.69 0.62 - 0.28 0.54 1.44 Audit fees are fees billed for professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for those fiscal years. It includes the audit of our Consolidated Financial Statements and other services that generally only the independent accountant reasonably can provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the SEC. Audit-Related Fees Audit-related fees are fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our Consolidated Financial Statements and not reported under the previous category. These services would include, among others: accounting consultations and audits in connection with acquisitions, internal control reviews, attest services that are not required by statue or regulation and consultation concerning financial accounting and reporting standards. Tax Fees Tax fees are fees billed for professional services for tax compliance, tax advice and tax planning. Pre-Approval Policies and Procedures Following the listing of our common shares on the NYSE, the Audit 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 and ensures key GeoPark 163 ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers The following table reflects purchases of our common shares by or on behalf of us or by any affiliated purchaser in 2015. (US$ per share) January 1 to January 31 February 1 to February 28 March 1 to March 31 April 1 to April 30 May 1 to May 31 June 1 to June 30 July 1 to July 31 August 1 to August 31 September 1 to September 30 October 1 to October 31 November 1 to November 30 December 1 to December 31 Total Total number of Maximum number common shares (or approximate dollar purchased as part value) of common Total number Average price of publicly shares that may yet of common shares paid per common announced plans be purchased under purchased share (US$) or programs the plans or programs 51,800 70,900 106,250 8,600 39,851 21,372 33,807 37,494 - - - - 4,69 4,09 4,03 4,74 5,38 5,14 4,38 3,73 - - - - 51,800 70,900 106,250 8,600 39,851 21,372 33,807 37,494 - - - - US$ 10 million US$ 10 million US$ 10 million US$ 10 million US$ 10 million US$ 10 million US$ 10 million US$ 10 million - - - - 370,074 4,36 370,074 In December 2014, the Board of Directors approved a program to repurchase ITEM 16F. Change in registrant’s certifying accountant up to US$10 million of common shares, par value US$0.001 per share of the Not applicable. Company. This Repurchase Program began on December 19, 2014 and expired on August 18, 2015. The Shares repurchased are used to offset, in part, any ITEM 16G. Corporate governance expected dilution effects resulting from the Company’s employee incentive schemes, including grants under the Company’s Stock Award Plan and the Our common shares are listed on the NYSE. We are therefore required to Limited Non-Executive Director Plan. comply with certain of the NYSE’s corporate governance listing standards (“NYSE Standards”). As a foreign private issuer, we may follow our home On April 5, 2016, we announced that we will resume our repurchase program country’s corporate governance practices in lieu of most of the NYSE of up to US$10 million of common shares, par value US$0.001 per share. The Standards. Our corporate governance practices differ in certain significant Repurchase Program will resume on April 6, 2016 and expire at the close of respects from those that U.S. companies must adopt in order to maintain NYSE business on May 9, 2016, but it may be terminated prior to this date. The share listing and, in accordance with Section 303A.11 of the NYSE Listed Company repurchases may be made from time-to-time through open market Manual, a brief, general summary of those differences is provided as follows. transactions, block trades, privately negotiated transactions or otherwise, and are subject to market and business conditions, levels of available liquidity, cash Director independence requirements for other purposes, regulatory, and other relevant factors. The The NYSE Standards require a majority of the membership of NYSE-listed shares repurchased will be used to offset, in part, any expected dilution effects company boards to be composed of independent directors. Neither Bermuda resulting from our employee incentive schemes, including grants under our law, the law of our country of incorporation, nor our memorandum of association Stock Award Plan and the Limited Non-Executive Director Plan. or bye-laws require a majority of our board to consist of independent directors. Non-management directors’ executive sessions The NYSE Standards require non-management directors of NYSE-listed companies to meet at regularly scheduled executive sessions without 164 GeoPark 20F management. Our memorandum of association and bye-laws do not require impose similar requirements, and consequently, our audit committee does not our non-management directors to hold such meetings. perform these additional functions. Our Audit Committee is composed Committee member composition The NYSE Standards require domestic NYSE-listed domestic companies to Miscellaneous exclusively of independent auditors. have a nominating/corporate governance committee and a compensation In addition to the above differences, we are not required to: make our audit committee that are composed entirely of independent directors. Bermuda law, and compensation committees prepare a written charter that addresses either the law of our country of incorporation, does not impose similar requirements. purposes and responsibilities or performance evaluations in a manner that would satisfy the NYSE’s requirements; acquire shareholder approval of equity Independence of the compensation committee and its advisers compensation plans in certain cases; or adopt and make publicly available On January 11, 2013, the SEC approved NYSE listing standards that require that corporate governance guidelines. the board of directors of a domestic listed company consider two factors (in addition to the existing general independence tests) in the evaluation of the We are incorporated under, and are governed by, the laws of Bermuda. For a independence of compensation committee members: (i) the source of summary of some of the differences between provisions of Bermuda law compensation of the director, including any consulting, advisory or other applicable to us and the laws applicable to companies incorporated in compensatory fees paid by the listed company, and (ii) whether the director Delaware and their shareholders, See “Item 10. Additional Information-B. has an affiliate relationship with the listed company, a subsidiary of the listed Memorandum of association and bye-laws.” company or an affiliate of a subsidiary of the listed company. In addition, before selecting or receiving advice from a compensation consultant or other ITEM 16H. Mine safety disclosure adviser, the compensation committee of a listed company will be required to Not applicable. 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 GeoPark 165 PART III ITEM 17. Financial statements We have responded to Item 18 in lieu of this item. ITEM 19. Exhibits Exhibit no. Description ITEM 18. Financial statements 1.1 Certificate of Incorporation (incorporated herein by reference to Financial Statements are filed as part of this annual report, see pages F-1 Exhibit 3.1 to the Company’s Registration Statement on Form F-1 to F-82 to this annual report. 166 GeoPark 20F (File No. 333-191068) filed with the SEC on September 9, 2013). 1.2 Memorandum of Association (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 1.3 Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 1.4 Form of amended and restated bye-laws (incorporated herein by reference to Exhibit 3.4 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 2.2 Indenture, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Limited, GeoPark Latin America Limited and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 2.3 Share Pledge Agreement, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Chile S.A., GeoPark Colombia S.A. and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 2.4 Intercompany Loan Pledge Agreement, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Fell S.p.A., GeoPark Llanos SAS and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.4 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 2.5 Supplemental Indenture, dated December 20, 2013, among GeoPark Latin America Limited Agencia en Chile, GeoPark Latin America Limited, GeoPark Limited, GeoPark Latin America Coöperatie U.A. and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.5 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on January 21, 2014). 4.1 Special Contract for the Exploration and Exploitation of Hydrocarbons, Fell Block, dated April 29, 1997, among the Republic of Chile, the Chilean Empresa Nacional de Petróleo (ENAP) and Cordex Petroleums Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). Exhibit no. Description Exhibit no. Description 4.2 Exploration and Production Contract regarding exploration for 4.10 Subordinated Loan Agreement, dated December 18, 2012, and exploitation of hydrocarbons in the La Cuerva Block, dated between LG International Corporation and Winchester Oil & Gas April 16, 2008, between the Colombian Agencia Nacional de S.A. (incorporated herein by reference to Exhibit 10.10 to the Hidrocarburos and Hupecol Caracara LLC (incorporated herein Company’s Registration Statement on Form F-1 (File No. by reference to Exhibit 10.12 to the Company’s Registration 333-191068) filed with the SEC on September 9, 2013). Statement on Form F-1 (File No. 333-191068) filed with the SEC 4.11 Subscription Agreement, dated October 18, 2011, among LG on September 9, 2013). International Corporation and GeoPark TdF S.A. (incorporated 4.3 Exploration and Production Contract regarding exploration for herein by reference to Exhibit 10.11 to the Company’s and exploitation of hydrocarbons in the Llanos 34 Block, dated Registration Statement on Form F-1 (File No. 333-191068) filed March 13, 2009, between the Colombian Agencia Nacional de with the SEC on September 9, 2013). Hidrocarburos and Unión Temporal Llanos 34 (incorporated 4.12 Shareholders’ Agreement, dated October 4, 2011, among LG herein by reference to Exhibit 10.3 to the Company’s Registration International Corporation, GeoPark TdF S.A. and GeoPark Chile Statement on Form F-1 (File No. 333-191068) filed with the SEC S.A. (incorporated herein by reference to Exhibit 10.12 to the on September 9, 2013). Company’s Registration Statement on Form F-1 (File No. 4.4 Subscription and Shareholders Agreement, dated February 7, 333-191068) filed with the SEC on September 9, 2013). 2006, among the International Finance Corporation, GeoPark 4.13 Holdings Limited, Gerald O’Shaughnessy and James F. Park (incorporated herein by reference to Exhibit 10.4 to the Company’s Registration Statement on Form F-1 (File No. Quota Purchase Agreement, dated May 14, 2013, between Panoro Energy do Brasil Ltda. and GeoPark Brasil Exploracăo e Producăo de Petróleo e Gás Ltda (incorporated herein by reference to Exhibit 10.13 to the Company’s Registration 333-191068) filed with the SEC on September 9, 2013). Statement on Form F-1 (File No. 333-191068) filed with the SEC 4.5 Purchase and Sale Agreement, dated March 26, 2012, between on September 9, 2013). Hupecol Cuerva Holdings LLC and GeoPark Llanos SAS 4.14 Purchase and Sale Agreement for Crude Oil and Condensate of (incorporated herein by reference to Exhibit 10.5 to the Fell Block between Empresa Nacional del Petróleo (ENAP) and Company’s Registration Statement on Form F-1 (File No. GeoPark Fell S.p.A. (incorporated herein by reference to Exhibit 333-191068) filed with the SEC on September 9, 2013). 10.14 to the Company’s Registration Statement on Form F-1 (File 4.6 Subscription Agreement, dated May 20, 2011, among LG No. 333-191068) filed with the SEC on September 9, 2013). International Corporation, GeoPark Chile Limited Agencia en 4.15 Purchase and Sale Agreement for Natural Gas between GeoPark Chile, GeoPark Chile S.A. and GeoPark Holdings Limited Chile Limited Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.6 to the (incorporated herein by reference to Exhibit 10.15 to the Company’s Registration Statement on Form F-1 (File No. Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on September 9, 2013). 333-191068) filed with the SEC on October 10, 2013).† 4.7 Shareholders’ Agreement, dated May 20, 2011, among LG 4.16 First Addendum and Amendment to Purchase and Sale International Corporation, GeoPark Chile Limited Agencia en Chile Agreement for Natural Gas between GeoPark Chile Limited and GeoPark Chile S.A. (incorporated herein by reference to Agencia en Chile and Methanex Chile S.A. (incorporated herein Exhibit 10.7 to the Company’s Registration Statement on Form F-1 by reference to Exhibit 10.16 to the Company’s Registration (File No. 333-191068) filed with the SEC on September 9, 2013). Statement on Form F-1/A (File No. 333-191068) filed with the SEC 4.8 Subscription Agreement, dated December 18, 2012, among LG on October 10, 2013).† International Corporation, GeoPark Chile Limited Agencia en 4.17 Second Addendum and Amendment to Purchase and Sale Chile, GeoPark Colombia S.A. and GeoPark Holdings Limited Agreement for Natural Gas between GeoPark Chile Limited (incorporated herein by reference to Exhibit 10.8 to the Agencia en Chile and Methanex Chile S.A. (incorporated herein Company’s Registration Statement on Form F-1 (File No. by reference to Exhibit 10.7 to the Company’s Registration 333-191068) filed with the SEC on September 9, 2013). Statement on Form F-1/A (File No. 333-191068) filed with the SEC 4.9 Shareholders’ Agreement, dated December 18, 2012, among LG on September 26, 2013). International Corporation, GeoPark Chile Limited Agencia en Chile 4.18 Third Addendum and Amendment to Purchase and Sale and GeoPark Colombia S.A. (incorporated herein by reference to Agreement for Natural Gas between GeoPark Chile Limited Agencia Exhibit 10.9 to the Company’s Registration Statement on Form F-1 en Chile and Methanex Chile S.A. (incorporated herein by reference (File No. 333-191068) filed with the SEC on September 9, 2013). to Exhibit 10.18 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).† GeoPark 167 Exhibit no. Description Exhibit no. Description 4.19 Fourth Addendum and Amendment to Purchase and Sale 99.1 Reserves Report of DeGolyer and MacNaughton dated April 15, Agreement for Natural Gas between GeoPark Chile Limited 2016, for reserves in Chile, Colombia, Brazil and pro forma Peru as Agencia en Chile and Methanex Chile S.A. (incorporated herein of December 31, 2015.* by reference to Exhibit 10.19 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC * Filed with this Annual Report on Form 20-F. on October 10, 2013).† † Confidential treatment of certain provisions of these exhibits has been 4.20 Fifth Addendum and Amendment to Purchase and Sale requested with the SEC. Omitted material for which confidential treatment has Agreement for Natural Gas between GeoPark Chile Limited been requested has been filed separately with the SEC. Agencia en Chile and Methanex Chile S.A. dated April 1, 2014. (incorporated herein by reference to Exhibit 4.23 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2015)† 4.21 Sixth Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited Agencia en Chile and Methanex Chile S.A. dated May 1, 2015.* † 4.22 Members’ Agreement, dated January 8, 2014, among GeoPark 4.23 Latin 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). Loan Agreement no. 4131, dated March 28, 2014, between Itaú BBA International plc and GeoPark Brasil Exploracăo e Produçăo de Petróleo e Gás Ltda. (incorporated herein by reference to Exhibit 4.21 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2014) 4.24 Addendum and Amendment to Loan Agreement no. 4131, dated March 12, 2015, between Itaú BBA International plc and GeoPark Brasil Exploracăo e Produçăo de Petróleo e Gás Ltda. (incorporated herein by reference to Exhibit 4.22 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2015) 4.25 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.* Subsidiaries of GeoPark Limited.* Certification pursuant to section 302 of the Sarbanes-Oxley Act 8.1 12.1 of 2002.* 12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* 13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* 13.2 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* 15.1 15.2 Consent of Price Waterhouse & Co. S.R.L., Argentina.* Consents of DeGolyer and MacNaughton to use its report.* 168 GeoPark 20F Glossary of oil and natural gas terms The terms defined in this section are used throughout this annual report: separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in “appraisal well” means a well drilled to further confirm and evaluate the presence overlapping or adjacent fields may be treated as a single or common operational of hydrocarbons in a reservoir that has been discovered. field. The geological terms structural feature and stratigraphic condition are “API” means the American Petroleum Institute’s inverted scale for denoting the intended to identify localized geological features as opposed to the broader “light” or “heaviness” of crude oils and other liquid hydrocarbons. terms of basins, trends, provinces, plays, areas-of-interest, etc. “bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in “formation” means a layer of rock which has distinct characteristics that differ reference to crude oil, condensate or natural gas liquids. from nearby rock. “bcf” means one billion cubic feet of natural gas. “mbbl” means one thousand barrels of crude oil, condensate or natural gas liquids. “bcm” means billion cubic meters. “mboe” means one thousand barrels of oil equivalent. “boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being “mcf” means one thousand cubic feet of natural gas. equivalent to one barrel of oil. “boepd” means barrels of oil equivalent per day. “bopd” means barrels of oil per day. “Measurements” include: • “m” or “meter” means one meter, which equals approximately 3.28084 feet; • “km” means one kilometer, which equals approximately 0.621371 miles; “British thermal unit” or “btu” means the heat required to raise the temperature • “sq. km” means one square kilometer, which equals approximately 247.1 acres; of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. • “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent to “basin” means a large natural depression on the earth’s surface in which approximately 0.15898 cubic meters; sediments generally brought by water accumulate. • “boe” means one barrel of oil equivalent, which equals approximately “CEOP” (Contrato Especial de Operación) means a special operating contract the 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of Chilean signs with a company or a consortium of companies for the exploration natural gas to one barrel of oil; and exploitation of hydrocarbon wells • “cf” means one cubic foot; “completion” means the process of treating a drilled well followed by the • “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, installation of permanent equipment for the production of natural gas or oil, or in respectively; the case of a dry hole, the reporting of abandonment to the appropriate agency. • “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, “developed acreage” means the number of acres that are allocated or assignable respectively; to productive wells or wells capable of production. • “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, “developed reserves” are expected quantities to be recovered from existing wells respectively; and and facilities. Reserves are considered developed only after the necessary • “pd” means per day. equipment has been installed or when the costs to do so are relatively minor “metric ton” or “MT” means one thousand kilograms. Assuming standard quality compared to the cost of a well. Where required facilities become unavailable, it oil, one metric ton equals 7.9 bbl. may be necessary to reclassify developed reserves as undeveloped. “mmbbl” means one million barrels of crude oil, condensate or natural gas liquids. “development well” means a well drilled within the proved area of an oil or gas “mmboe” means one million barrels of oil equivalent. reservoir to the depth of a stratigraphic horizon known to be productive. “mmbtu” means one million British thermal units. “dry hole” means a well found to be incapable of producing hydrocarbons in “NYMEX” means The New York Mercantile Exchange. sufficient quantities such that proceeds from the sale of such production exceed “net acres” means the percentage of total acres an owner has out of a particular production expenses and taxes. number of acres, or a specified tract. An owner who has a 50% interest in 100 “E&P Contract” means exploration and production contract acres owns 50 net acres. “economic interest” means an indirect participation interest in the net revenues “productive well” means a well that is found to be capable of producing from a given block based on bilateral agreements with the concessionaires. hydrocarbons in sufficient quantities such that proceeds from the sale of the “economically producible” means a resource that generates revenue that production exceed production expenses and taxes. exceeds, or is reasonably expected to exceed, the costs of the operation. “prospect” means a potential trap which may contain hydrocarbons and is “exploratory well” means a well drilled to find and produce oil or gas in an supported by the necessary amount and quality of geologic and geophysical unproved area, to find a new reservoir in a field previously found to be data to indicate a probability of oil and/or natural gas accumulation ready to be productive of oil or gas in another reservoir, or to extend a known reservoir. drilled. The five required elements (generation, migration, reservoir, seal and trap) Generally, an exploratory well is any well that is not a development well, a service must be present for a prospect to work and if any of them fail neither oil nor well, or a stratigraphic test well as those items are defined below. natural gas will be present, at least not in commercial volumes. “field” means an area consisting of a single reservoir or multiple reservoirs all “proved developed reserves” means those proved reserves that can be grouped on or related to the same individual geological structural feature and/ expected to be recovered through existing wells and facilities and by existing or stratigraphic condition. There may be two or more reservoirs in a field that are operating methods. GeoPark 169 “proved reserves” means estimated quantities of crude oil, natural gas, and types of expendable holes related to hydrocarbon exploration. Stratigraphic test natural gas liquids which geological and engineering data demonstrate with wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) reasonable certainty to be economically recoverable in future years from known development-type, if drilled in a proved area. reservoirs under existing economic and operating conditions, as well as “tcm” means trillion cubic meters. additional reserves expected to be obtained through confirmed improved “undeveloped reserves” are quantities expected to be recovered through future recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2). investments: (1) from new wells on undrilled acreage in known accumulation, (2) “proved undeveloped reserves” means are those proved reserves that are from deepening existing wells to a different (but known) reservoir, (3) from infill expected to be recovered from future wells and facilities, including future wells that will increase recover, or (4) where a relatively large expenditure ( e.g. , improved recovery projects which are anticipated with a high degree of when compared to the cost of drilling a new well) is required to (a) recomplete certainty in reservoirs which have previously shown favorable response to an existing well or (b) install production or transportation facilities for primary or improved recovery projects. 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 is field, rather than a single tract, to provide for development and operation either producing or not producing and completing new reservoirs in an attempt without regard to separate property interests. Also, the area covered by a 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 explore there must exist, or there must be a reasonable expectation that there will for and to produce and own oil, gas, or other minerals. The working interest exist, a revenue interest in the production, installed means of delivering oil, owners bear the exploration, development, and operating costs on either a cash, gas, or related substances to market, and all permits and financing required to penalty, or carried basis. 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 are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all 170 GeoPark 20F 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 James F. Park Chief Executive Officer and Deputy Chairman April 15, 2016 GeoPark 171 Consolidated Financial Statements As of and for the year ended 31 December 2015 172 GeoPark 20F Index to Consolidated Financial Statements Audited Annual Consolidated Financial Statements-GeoPark Limited Report of Independent Registered Public Accounting Firm Consolidated Statements of Income and Comprehensive Income Consolidated Statement of Financial Position Consolidated Statements of Changes in Shareholders’ Equity Consolidated Statements of Cash Flows Notes to the Audited Annual Consolidated Financial Statements 176 177 178 179 180 181 GeoPark 173 Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of GeoPark Limited In our opinion, the accompanying consolidated statement of financial position and the related consolidated statements of income, comprehensive income, changes in equity, and cash flow present fairly, in all material respects, the financial position of GeoPark Limited and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/ PRICE WATERHOUSE & CO. S.R.L. By /s/ Carlos Martín Barbafina (Partner) Carlos Martín Barbafina Autonomous City of Buenos Aires, Argentina March 9, 2016 174 GeoPark 20F Consolidated Statement of Income Amounts in US$ ´000 Note 2015 2014 2013 Net Revenue Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful efforts Impairment loss for non-financial assets Other (expenses) income Operating (Loss) Profit Financial costs Foreign exchange loss (Loss) Profit Before Income Tax Income tax benefit (expense) (Loss) Profit For The Year Attributable to: Owners of the Company Non-controlling interest (Losses) Earnings per share (in US$) for (loss) profit attributable to owners of the Company. Basic (Losses) Earnings per share (in US$) for (loss) profit attributable to owners of the Company. Diluted Consolidated Statement of Comprehensive Income Amounts in US$ ´000 (Loss) Profit for the year Other comprehensive income: Items that may be subsequently reclassified to (loss) profit Currency translation difference Total comprehensive (Loss) Income for the year Attributable to: Owners of the Company Non-controlling interest 428,734 338,353 (131,419) (111,296) 209,690 (86,742) (13,831) (37,471) (5,211) (13,002) (45,867) (24,428) 7 8 11 12 13 19 (105,557) (100,528) (30,084) (30,367) 19-36 (149,574) (13,711) (232,491) (35,655) (33,474) (301,620) 14 (9,430) (1,849) 71,844 (27,622) (23,097) 21,125 (5,292) (44,962) (17,252) (69,968) (10,962) - 5,343 83,964 (33,115) (761) 50,088 16 17,054 (284,566) (5,195) 15,930 (15,154) 34,934 (234,031) (50,535) 8,085 7,845 22,521 12,413 18 18 (4.05) 0.14 0.52 (4.05) 0.14 0.48 2015 2014 2013 (284,566) 15,930 34,934 (1,001) (285,567) (2,448) 13,482 (1,956) 32,978 (235,032) (50,535) 5,637 7,845 20,565 12,413 The notes on pages 181 to 225 are an integral part of these consolidated financial statements. GeoPark 175 Consolidated Statement of Financial Position Amounts in US$ ´000 Note 2015 2014 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 at bank and in hand Total Current Assets Total Assets Total Equity Equity attributable to owners of the Company Share capital Share premium Reserves (Accumulated losses) Retained earnings 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 Current income tax liabilities Trade and other payables Total Current Liabilities Total Liabilities Total Equity and Liabilities The financial statements were approved by the Board of Directors on 9 March 2016. The notes on pages 181 to 225 are an integral part of these consolidated financial statements. 176 GeoPark 20F 19 21 24 17 23 22 23 23 21 24 24 522,611 790,767 1,172 13,306 34,646 220 1,253 12,979 33,195 349 571,955 838,543 4,264 13,480 11,057 19,195 1,118 82,730 8,532 36,917 13,993 13,459 - 127,672 131,844 200,573 703,799 1,039,116 25 59 232,005 123,016 (208,428) 146,652 53,515 200,167 58 210,886 124,017 40,596 375,557 103,569 479,126 26 27 17 28 26 28 343,248 342,440 42,450 16,955 19,556 46,910 30,065 16,583 422,209 435,998 35,425 208 45,790 81,423 503,632 27,153 7,935 88,904 123,992 559,990 703,799 1,039,116 Consolidated Statement of Changes In Equity Amount in US$ ‘000 Equity at 1 January 2013 Comprehensive income: Profit for the year Currency translation differences Total Comprehensive Income for the Year 2013 Transactions with owners: Proceeds from transaction with Non-controlling interest (Notes 25 and 34) Share-based payment (Note 29) Repurchase of shares (Note 25) Total 2013 Balances at 31 December 2013 Comprehensive income: Profit for the year Currency translation differences Total Comprehensive Income for the Year 2014 Transactions with owners: Proceeds from issue of shares Proceeds from transaction with Non-controlling interest (Notes 25 and 34) Share-based payment (Note 29) Repurchase of shares (Note 25) Total 2014 Balances at 31 December 2014 Comprehensive income: Loss for the year Currency translation differences Total Comprehensive Loss for the Year 2015 Transactions with owners: Share-based payment (Note 29) Repurchase of shares (Note 25) Total 2015 Balances at 31 December 2015 (1) See Note 1. Attributable to owners of the Company (Accumulated losses) Non- Share Capital(1) 43 Share Other Translation Retained controlling Premium Reserve Reserve earnings 116,817 127,527 894 (5,860) Interest 72,665 Total 312,086 - - - - 1 - 1 - - - - 4,049 (440) 3,609 - - - - - - - 44 120,426 127,527 (1,062) - 22,521 12,413 (1,956) (1,956) - - 22,521 12,413 34,934 (1,956) 32,978 - - - - - - - - - - - - - (2,448) (2,448) - - - - - - 7,245 - 7,245 23,906 8,085 - 8,085 - - 8,605 - 8,605 40,596 9,529 509 - 10,038 95,116 7,845 - 7,845 9,529 11,804 (440) 20,893 365,957 15,930 (2,448) 13,482 - 90,862 35 573 - 608 35 9,178 (388) 99,687 103,569 479,126 210,886 127,527 (3,510) - - - 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 - - - - - - 14 90,848 - - (388) 90,460 - - - 14 58 - - - 1 - 1 The notes on pages 181 to 225 are an integral part of these consolidated financial statements. GeoPark 177 Consolidated Statement of Cash Flow Amounts in US$ ´000 Note 2015 2014 2013 Cash flows from operating activities (Loss) Profit for the year Adjustments for: Income tax (benefit) expense Depreciation Allowance for doubtful accounts Loss on disposal of property, plant and equipment Impairment loss for non-financial assets Write-off of unsuccessful efforts Accrual of borrowing’s interests Amortisation of other long-term liabilities Unwinding of long-term liabilities Accrual of share-based payment Foreign exchange loss Income tax paid Changes in working capital Cash flows from operating activities – net Cash flows from investing activities Purchase of property, plant and equipment Acquisitions of companies, net of cash acquired Collections related to financial leases Cash flows used in investing activities – net Cash flows from financing activities Proceeds from borrowings Proceeds from transaction with non-controlling interest(1) Proceeds from loans from related parties Proceeds from issuance of shares Repurchase of shares Principal paid to related parties Principal paid Interest paid (284,566) 15,930 34,934 16 13-23 (17,054) 105,557 - 2,000 19-36 149,574 19 27 27 5 30,084 28,460 (703) 2,575 8,223 33,474 (7,625) (24,104) 25,895 5,195 100,528 741 590 9,430 30,367 25,754 (468) 1,972 8,373 23,097 (1,306) 10,543 230,746 15,154 69,968 - 575 - 10,962 22,085 (1,165) 1,523 9,167 761 (4,040) (32,629) 127,295 (48,842) (238,047) (215,234) - - (114,967) 8,973 - 6,734 (48,842) (344,041) (208,500) 7,036 67,633 - 2,400 - (1,615) - (89) (25,754) 35 16,563 90,862 (388) (8,344) (17,087) (24,558) 307,259 40,667 8,344 3,442 (440) - (179,360) (15,894) 164,018 Cash flows (used in) / from financing activities - net (18,022) 124,716 Net (decrease) increase in cash and cash equivalents (40,969) 11,421 82,813 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 Cash in hand Bank overdrafts Cash and cash equivalents 127,672 (3,973) 82,730 121,105 (4,854) 38,292 - 127,672 121,105 82,720 127,560 121,113 10 - 112 - 22 (30) 82,730 127,672 121,105 The notes on pages 181 to 225 are an integral part of these consolidated financial statements. (1) Proceeds from transaction with Non-controlling interest for the year ended 31 December 2013 includes: US$ 9,529,000 from capital contributions received in the period; and US$ 31,138,000 as result of collection of receivables included in Prepayment and other receivables as of 31 December 2012, relating to equity transactions made in 2012 and 2011. 178 GeoPark 20F Notes Note 1 General Information 2.1.1 Changes in accounting policy and disclosure During 2015, the Management of the Company has changed the presentation of the Consolidated Statement of Income re-ordering the profit and loss line GeoPark Limited (the Company) is a company incorporated under the law of items, eliminating gross profit and showing the depreciation and write off of Bermuda. The Registered Office address is Cumberland House, 9th Floor, 1 unsuccessful efforts lines separately. This change is intended to provide the Victoria Street, Hamilton HM11, Bermuda. financial statements users with more relevant information and a better explanation of the elements of performance. This change has been applied to The principal activity of the Company and its subsidiaries (“the Group”) are 2014 and 2013, for comparative purposes. exploration, development and production for oil and gas reserves in Chile, Colombia, Brazil, Peru and Argentina. The Group has working interests and/or If previous year’s disclosure had not changed, the Consolidated Statement of economic interests in 35 hydrocarbon blocks. Income would have been as follows: These consolidated financial statements were authorised for issue by the Consolidated Statement of Income Board of Directors on 9 March 2016. Note 2 Summary of significant accounting policies Amounts in US$ ´000 Net Revenue Production costs Gross Profit 2015 2014 2013 209,690 428,734 338,353 (188,575) (229,650) (179,643) 21,115 199,084 158,710 The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been Exploration costs consistently applied to the years presented, unless otherwise stated. Administrative costs Selling expenses (43,915) (41,195) (5,211) 2.1 Basis of preparation Impairment loss for non-financial assets (149,574) The consolidated financial statements of GeoPark Limited have been prepared Other Operating (Loss) / Income in accordance with International Financial Reporting Standards (“IFRS”) as Operating (Loss) Profit (13,711) (232,491) issued by the International Accounting Standards Board (“IASB”). (43,369) (48,164) (24,428) (9,430) (1,849) 71,844 (16,254) (46,584) (17,252) - 5,344 83,964 The consolidated financial statements are presented in thousands (US$’000) of (Loss) Profit Before Income Tax United States Dollars and all values are rounded to the nearest thousand (US$’000), except in the footnotes and where otherwise indicated. Income tax benefit (expense) (Loss) Profit for the Year The consolidated financial statements have been prepared on a historical cost basis. Financial results (69,129) (301,620) (50,719) 21,125 (33,876) 50,088 17,054 (284,566) (5,195) 15,930 (15,154) 34,934 The preparation of financial statements in conformity with IFRS requires the The Company has also revised its consolidated statement of income and the use of certain critical accounting estimates. It also requires management to consolidated statement of changes in equity for the years ended 31 December exercise its judgement in the process of applying the Group’s accounting 2014 and 2013, to properly record the accrual of its share-based payments policies. The areas involving a higher degree of judgement or complexity, or costs recognized during 2014 and 2013, originally allocated in full to the areas where assumptions and estimates are significant to the consolidated Company’s owners for a total amount of US$ 573,000 and US$ 509,000, financial statements are disclosed in this note under the title “Accounting respectively. These adjustments had no change in total profit for 2014 and estimates and assumptions”. 2013 or to total equity originally reported. The Company concluded that the adjustments were not material to the consolidated statement of income and All the information included in these consolidated financial statements the consolidated statement of changes in equity for the years ended 31 corresponds to the Group, except where otherwise indicated. December 2014 and 2013. GeoPark 179 New and amended standards adopted by the Group are treated in a similar way to finance leases applying IAS 17. Leases are ‘capitalized’ by recognizing the present value of the lease payments and The following standards have been adopted by the Group for the first time for showing them either as lease assets (right-of-use assets) or together with the financial year beginning on or after 1 January 2015: property, plant and equipment. Annual Improvements to IFRSs – 2010-2012 Cycle and 2011 – 2013 Cycle Defined Benefit Plans: Employee Contributions – Amendments to IAS 19 If lease payments are made over time, a company also recognizes a financial liability representing its obligation to make future lease payments. The most The adoption of these amendments did not have any impact on the current significant effect will be an increase in lease assets and financial liabilities. The period or any prior period and is not likely to affect future periods. Group is yet to assess IFRS 16’s full impact and intends to adopt it no later than New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2015 and not early adopted. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future Amendment to IFRS 9 ‘Financial Instruments’ addresses the classification, reporting periods and on foreseeable future transactions. the accounting period beginning on or after 1 January 2019. measurement and derecognition of financial assets and financial liabilities and introduces new rules for hedge accounting. 2.2 Going concern In July 2014, the IASB made further changes to the classification and The Directors regularly monitor the Group’s cash position and liquidity risks measurement rules and also introduced a new impairment model. These latest throughout the year to ensure that it has sufficient funds to meet forecast amendments now complete the new financial instruments standard. Following operational and investment funding requirements. Sensitivities are run to the changes approved by the IASB in July 2014, the group no longer expects reflect latest expectations of expenditures, oil and gas prices and other factors any impact from the new classification, measurement and derecognition to enable the Group to manage the risk of any funding short falls and/or rules on the group’s financial assets and financial liabilities. There will also potential debt covenant breaches. be no impact on the Group’s accounting for financial liabilities, as the new requirements only affect the accounting for financial liabilities that are Considering macroeconomic environment conditions (see Note 35), the designated at fair value through profit or loss and the Group does not have performance of the operations, Group’s cash position, the offtake and the any such liabilities. prepayment agreement signed with Trafigura (see Note 3) and over 80% of The Group is yet to assess amendment to IFRS 9’s full impact and intends to adopt its total indebtedness maturing in 2020, the Directors have formed a it no later than the accounting period beginning on or after 1 January 2018. judgement, at the time of approving the financial statements, that there is a IFRS 15 ‘Revenue from Contracts with Customers’: the IASB has issued a new its obligations for the foreseeable future. For this reason, the Directors have standard for the recognition of revenue. This will replace IAS 18 which covers continued to adopt the going concern basis in preparing the consolidated reasonable expectation that the Group has adequate resources to meet all contracts for goods and services and IAS 11 which covers construction financial statements. contracts. The new standard is based on the principle that revenue is recognized when control of a good or service transfers to a customer – so the 2.3 Consolidation notion of control replaces the existing notion of risks and rewards. The Subsidiaries are all entities (including structured entities) over which the standard permits a modified retrospective approach for the adoption. Under group has control. The Group controls an entity when the Group is exposed to, this approach entities will recognize transitional adjustments in retained or has rights to, variable returns from its involvement with the entity and has earnings on the date of initial application (eg 1 January 2017), ie without the ability to affect those returns through its power over the entity. Subsidiaries restating the comparative period. They will only need to apply the new rules to are fully consolidated from the date on which control is transferred to the contracts that are not completed as of the date of initial application. The Group Group. They are deconsolidated from the date that control ceases. is yet to assess amendment to IFRS 15’s full impact and intends to adopt it no later than the accounting period beginning on or after 1 January 2017. The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary IFRS 16 ‘Leases’: the IASB has issued in January 2016 a new standard that sets is the fair values of the assets transferred, the liabilities incurred to the former out the principles for the recognition, measurement, presentation and owners of the acquiree and the equity interests issued by the Group. The disclosure of leases for both parties to a contract, ie the customer (‘lessee’) and consideration transferred includes the fair value of any asset or liability the supplier (‘lessor’). IFRS 16 replaces the previous leases Standard, IAS 17 resulting from a contingent consideration arrangement. Identifiable assets Leases, and related Interpretations. IFRS 16 eliminates the classification of acquired and liabilities and contingent liabilities assumed in a business leases as either operating leases or finance leases for a lessee. Instead all leases combination are measured initially at their fair values at the acquisition date. 180 GeoPark 20F Acquisition-related costs are expensed as incurred. 2.6 Joint arrangements The excess of the consideration transferred the amount of any non-controlling 2013. Under IFRS 11 investments in joint arrangements are classified as either interest in the acquiree and the acquisition-date fair value of any previous joint operations or joint ventures depending on the contractual rights and The company has applied IFRS 11 to all joint arrangements as of 1 January equity interest in the acquiree over the fair value of the identifiable net assets obligations each investor. acquired is recorded as goodwill. If the total of consideration transferred, non-controlling interest recognized and previously held interest measured is The Company has assessed the nature of its joint arrangements and less than the fair value of the net assets of the subsidiary acquired in the case determined them to be joint operations. The company combines its share in of a bargain purchase, the difference is recognized directly in the income the joint operations individual assets, liabilities, results and cash flows on a statement. line-by-line basis with similar items in its financial statements. Intercompany transactions, balances and unrealised gains on transactions 2.7 Revenue recognition between the Group and its subsidiaries are eliminated. Unrealised losses are Revenue from the sale of crude oil and gas is recognised in the Statement of also eliminated unless the transaction provides evidence of an impairment of Income when risk transferred to the purchaser, and if the revenue can be the asset transferred. Amounts reported in the financial statements of measured reliably and is expected to be received. Revenue is shown net of subsidiaries have been adjusted where necessary to ensure consistency with VAT, discounts related to the sale and overriding royalties due to the ex-owners the accounting policies adopted by the Group. of oil and gas properties where the royalty arrangements represent a retained working interest in the property. 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 net decision-maker, who is responsible for allocating resources and assessing revenue 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 costs People departments. This committee reviews the Group’s internal reporting in Financial costs include interest expenses, realised and unrealised gains and order to assess performance and allocate resources. Management has losses arising from transactions in foreign currencies and the amortisation of determined the operating segments based on these reports. financial assets and liabilities. The Company has capitalised borrowing cost for 2.5 Foreign currency translation a) Functional and presentation currency wells and facilities that were initiated after 1 January 2009. Amounts capitalised during the year totalled US$ 637,390 (US$ 3,112,317 in 2014 and US$ 1,312,953 in 2013). The consolidated financial statements are presented in US Dollars, which is the 2.10 Property, plant and equipment Group’s presentation currency. Property, plant and equipment are stated at historical cost less depreciation and impairment charge, if applicable. Historical cost includes expenditure that Items included in the financial statements of each of the Group’s entities are is directly attributable to the acquisition of the items; including provisions for measured using the currency of the primary economic environment in which asset retirement obligation. the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Chile, Colombia, Peru and Argentina is the Oil and gas exploration and production activities are accounted for in US Dollar, meanwhile for the Group Brazilian company the functional currency accordance with the successful efforts method on a field by field basis. The is the local currency, which is the Brazilian Real. Group accounts for exploration and evaluation activities in accordance with b) Transactions and balances IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exploration and evaluation costs until such time as the economic viability of Foreign currency transactions are translated into the functional currency using producing the underlying resources is determined. Costs incurred prior to the exchange rates prevailing at the dates of the transactions. Foreign obtaining legal rights to explore are expensed immediately to the Consolidated exchange gains and losses resulting from the settlement of such transactions Statement of Income. and from the translation at period end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the Consolidated Exploration and evaluation costs may include: license acquisition, geological Statement of Income. and geophysical studies (i.e.: seismic), direct labour costs and drilling costs of GeoPark 181 exploratory wells. No depreciation and/or amortisation are charged during the 2.11 Provisions and other long-term liabilities exploration and evaluation phase. Upon completion of the evaluation phase, Provisions for asset retirement obligations, deferred income, restructuring the prospects are either transferred to oil and gas properties or charged to obligations and legal claims are recognised when the Group has a present expense (exploration costs) in the period in which the determination is made legal or constructive obligation as a result of past events; it is probable that an depending whether they have found reserves or not. If not developed, outflow of resources will be required to settle the obligation; and the amount exploration and evaluation assets are written off after three years, unless it can has been reliably estimated. Restructuring provisions comprise lease be clearly demonstrated that the carrying value of the investment is termination penalties and employee termination payments. recoverable. A charge of US$ 30,084,000 has been recognised in the Consolidated be required to settle the obligation using a pre-tax rate that reflects current Statement of Income (US$ 30,367,000 in 2014 and US$ 10,962,000 in 2013) for market assessments of the time value of money and the risks specific to the write-offs (see Note 19). obligation. The increase in the provision due to passage of time is recognised Provisions are measured at the present value of the expenditures expected to All field development costs are considered construction in progress until they are finished and capitalised within oil and gas properties, and are subject to 2.11.1 Asset Retirement Obligation as interest expense. depreciation once complete. Such costs may include the acquisition and The Group records the fair value of the liability for asset retirement obligations installation of production facilities, development drilling costs (including dry in the period in which the wells are drilled. When the liability is initially holes, service wells and seismic surveys for development purposes), project- recorded, the Group capitalises the cost by increasing the carrying amount of related engineering and the acquisition costs of rights and concessions related the related long-lived asset. Over time, the liability is accreted to its present to proved properties. value at each reporting period, and the capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and Workovers of wells made to develop reserves and/or increase production are application of current legislation and on the basis of the changes in capitalized as development costs. Maintenance costs are charged to income technology and the variations in the costs of restoration necessary to protect when incurred. the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this recalculation are Capitalised costs of proved oil and gas properties and production facilities and included in the financial statements in the period in which this recalculation is machinery are depreciated on a licensed area by the licensed area basis, using determined and reflected as an adjustment to the provision and the the unit of production method, based on commercial proved and probable corresponding property, plant and equipment asset. reserves. The calculation of the “unit of production” depreciation takes into account estimated future finding and development costs and is based on 2.11.2 Deferred Income current year end unescalated price levels. Changes in reserves and cost Relates to contributions received in cash from the Group’s clients to improve estimates are recognised prospectively. Reserves are converted to equivalent the project economics of gas wells. The amounts collected are reflected as a units on the basis of approximate relative energy content. deferred income in the balance sheet and recognised in the Consolidated Statement of Income over the productive life of the associated wells. The Depreciation of the remaining property, plant and equipment assets (i.e. depreciation of the gas wells that generated the deferred income is charged to furniture and vehicles) not directly associated with oil and gas activities has the Consolidated Statement of Income simultaneously with the amortisation been calculated by means of the straight line method by applying such annual of the deferred income. rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between 3 years and 10 years. 2.12 Impairment of non-financial assets Depreciation is allocated in the Consolidated Statement of Income as a exploration and evaluation assets) are tested annually for impairment. Assets separate line to better follow up the performance of the business. that are subject to depreciation and/or amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the An asset’s carrying amount is written down immediately to its recoverable carrying amount may not be recoverable. amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in An impairment loss is recognised for the amount by which the asset’s carrying Assets that are not subject to depreciation and/or amortisation (i.e.: Note 2.12). 182 GeoPark 20F amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a Deferred income tax is recognised, using the liability method, on temporary licensed area. Non-financial assets other than goodwill that suffered impairment differences arising between the tax bases of assets and liabilities and their are reviewed for possible reversal of the impairment at each 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 of substantially enacted by the balance sheet date and are expected to apply 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. The impairment loss recognised in 2015 amounted to US$ 149,574,000 In addition, the Group has tax-loss carry-forwards in certain taxing jurisdictions (US$ 9,430,000 in 2014, nil in 2013) See Note 36. The write-offs are detailed that are available to offset against future taxable profit. However, deferred tax in Note 19. 2.13 Lease contracts assets are recognized only to the extent that it is probable that taxable 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 All current lease contracts are considered to be operating leases on the basis the extent that actual outcomes differ from management’s estimates, taxation that the lessor retains substantially all the risks and rewards related to the charges or credits may arise in future periods. ownership of the leased asset. Payments related to operating leases and other rental agreements are recognised in the Consolidated Income Statement on a Deferred income tax liabilities are provided on taxable temporary differences straight line basis over the term of the contract. The Group’s total commitment arising from investments in subsidiaries and joint arrangements, except for relating to operating leases and rental agreements is disclosed in Note 31. deferred income tax liability where the timing of the reversal of the temporary Leases in which substantially all of the risks and rewards of ownership are difference will not reverse in the foreseeable future. The Group is able to transferred to the lessee are classified as finance leases. Under a finance control the timing of dividends from its subsidiaries and hence does not lease, the Company as lessor has to recognize an amount receivable equal to expect taxable profit. Hence deferred tax is recognized in respect of the the aggregate of the minimum lease payments plus any unguaranteed retained earnings of overseas subsidiaries only if at the date of the statements residual value accruing to the lessor, discounted at the interest rate implicit of financial position, dividends have been accrued as receivable or a binding difference is controlled by the Group and it is probable that the temporary in the lease. 2.14 Inventories agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Company 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 Company would have to recognize amounts to Crude oil is measured at the lower of cost and net realisable value. Materials approximately US$ 8,300,000. 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, first-out (FIFO) method. 2.16 Financial assets Financial assets are divided into the following categories: loans and 2.15 Current and deferred income tax receivables; financial assets at fair value through the profit or loss; available- The tax expense for the year comprises current and deferred tax. Tax is for-sale financial assets; and held-to-maturity investments. Financial assets are recognised in the Consolidated Statement of Income. assigned to the different categories by management on initial recognition, depending on the purpose for which the investments were acquired. The The current income tax charge is calculated on the basis of the tax laws designation of financial assets is re-evaluated at every reporting date at which enacted or substantially enacted at the balance sheet date in the countries a choice of classification or accounting treatment is available. where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of All financial assets are recognised when the Group becomes a party to the applicable tax laws and regulations in many jurisdictions. The resolution of tax contractual provisions of the instrument. All financial assets are initially positions taken by the Group, through negotiations with relevant tax recognised at fair value, plus transaction costs. authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all of the risks GeoPark 183 and rewards of ownership have been transferred. An assessment for 2.21 Borrowings impairment is undertaken at each balance sheet date. Borrowings are obligations to pay cash and are recognised when the Group becomes a party to the contractual provisions of the instrument. Interest and other cash flows resulting from holding financial assets are recognised in the Consolidated Income Statement when receivable, regardless Borrowings are recognised initially at fair value, net of transaction costs of how the related carrying amount of financial assets is measured. incurred. Borrowings are subsequently stated at amortised cost; any difference Loans and receivables are non-derivative financial assets with fixed or recognised in the Consolidated Statement of Income over the period of the determinable payments that are not quoted in an active market. They are borrowings using the effective interest method. included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. The Direct issue costs are charged to the Consolidated Statement of Income on an Group’s loans and receivables comprise trade receivables, prepayments and accruals basis using the effective interest method. between the proceeds (net of transaction costs) and the redemption value is other receivables and cash at bank and in hand in the balance sheet. They arise when the Group provides money, goods or services directly to a debtor with 2.22 Share capital no intention of trading the receivables. Loans and receivables are Equity comprises the following: subsequently measured at amortised cost using the effective interest method, • “Share capital” representing the nominal value of equity shares. less provision for impairment. Any change in their value through impairment • “Share premium” representing the excess over nominal value of the fair value or reversal of impairment is recognised in the Consolidated Statement of of consideration received for equity shares, net of expenses of the share issue. Income. All of the Group’s financial assets are classified as loan and receivables. • “Other reserve” representing: 2.17 Other financial assets issued at year end or, Non current other financial assets include contributions made for • the difference between the proceeds from the transaction with non- environmental obligations according to a Colombian government request. controlling interests received against the book value of the shares acquired in Current financial assets corresponds to short term investments with original the Chilean and Colombian subsidiaries. maturities up to twelve months and over three months. • “Translation reserve” representing the differences arising from translation of • the equity element attributable to shares granted according to IFRS 2 but not investments in overseas subsidiaries. 2.18 Impairment of financial assets • “(Accumulated losses) Retained earnings” representing accumulated earnings Provision against trade receivables is made when objective evidence is and losses. 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 2.23 Share-based payment write-down is determined as the difference between the asset’s carrying The Group operates a number of equity-settled and cash-settled share-based amount and the present value of estimated future cash flows. compensation plans comprising share awards payments and stock options plans to certain employees and other third party contractors. 2.19 Cash and cash equivalents Cash and cash equivalents includes cash in hand, deposits held at call with Share-based payment transactions are measured in accordance with IFRS 2. banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts, if any, are shown Fair value of the stock option plan for employee or contractors services within borrowings in the current liabilities section of the Consolidated received in exchange for the grant of the options is recognised as an expense. Statement of Financial Position. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted calculated using the 2.20 Trade and other payables Black-Scholes model. Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts Non-market vesting conditions are included in assumptions about the payable are classified as current liabilities if payment is due within one year or number of options that are expected to vest. At each balance sheet date, less (or in the normal operating cycle of the business if longer). If not, they are the entity revises its estimates of the number of options that are expected presented as non-current liabilities. to vest. It recognises the impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding Trade payables are recognised initially at fair value and subsequently adjustment to equity. measured at amortised cost using the effective interest method. 184 GeoPark 20F The fair value of the share awards payments is determined at the grant date by However, tax receivables (VAT) seldom match with local currency liabilities. reference of the market value of the shares and recognised as an expense over Therefore the Group maintains a net exposure to them. the vesting period. When the options are exercised, the Company issues new shares. The proceeds gas productive assets. Those assets, even in the local markets, are generally Most of the Group’s assets held in those countries are associated with oil and received net of any directly attributable transaction costs are credited to share settled in US Dollar equivalents. capital (nominal value) and share premium when the options are exercised. For cash-settled share-based payment transactions, the Company measures and 2013, respectively) against the US Dollar, the Chilean Peso devaluated by the services acquired for amounts that are based on the price of the 16% (16% and 10% in 2014 and 2013 respectively) and the Colombian Peso Company’s shares. The fair value of the liability incurred is measured using devaluated by 32% (24% and 9% in 2014 and 2013, respectively). During 2015, the Argentine Peso devaluated by 52% (31% and 33% in 2014 Geometric Brownian Motion method. Until the liability is settled, the Company is required to remeasure the fair value of the liability at each If the Argentine Peso, the Chilean Peso and the Colombian Peso had each reporting date and at the date of settlement, with any changes in value devaluated an additional 10% against the US dollar, with all other variables recognized in profit or loss for the period. held constant, post-tax loss for the year would have been higher by US$ Note 3 Financial Instruments-risk management 1,003,300 (post – tax profit lower by US$ 621,400 in 2014 and higher by US$ 279,000 in 2013). In Brazil the functional currency is the local currency, which is the Brazilian The Group is exposed through its operations to the following financial risks: Real. The fluctuation of the US Dollars against the Brazilian Real does not • Currency risk • Price risk • Credit risk – concentration • Funding and liquidity risk • Interest rate risk • Capital risk management impact the loans, costs and revenues held in Brazilian Real; but it does impact the balances denominated in US Dollars. Such is the case of the cash at bank and Itaú and intercompany loans. Most of the balances are denominated in Brazilian Real, and since it is the functional currency of the Brazilian subsidiary, there is no exposure to currency fluctuation except from cash at bank held in US Dollars and for the intercompany loan and Itaú loan described in Note 26. The exchange loss generated by the Brazilian subsidiary during 2015 The policy for managing these risks is set by the Board. Certain risks are amounted to US$ 35,605,000 (US$ 17,573,000 in 2014 and nil in 2013). managed centrally, while others are managed locally following guidelines communicated from the corporate office. The policy for each of the above risks During 2015, the Brazilian Real devaluated by 47% against the US Dollar (13% is described in more detail below. Currency risk and 15% in 2014 and 2013, respectively). If the Brazilian Real had devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax loss for the year would have been higher by US$ 7,400,000 (post – tax In Argentina, Colombia, Chile and Peru the functional currency is the US Dollar. The profit lower by US$ 5,660,000 in 2014 and higher by US$ 3,652,000 in 2013). fluctuation of the local currencies of these countries against the US Dollar does not impact the loans, costs and revenues held in US Dollars; but it does impact the As of 31 December 2015, the balances denominated in the Peruvian local balances denominated in local currencies. Such is the case of the prepaid taxes. currency (Peruvian Soles) are not material. In Chile, Colombia and Argentina subsidiaries most of the balances are As currency rate changes between the US Dollar and the local currencies, the denominated in US Dollars, and since it is the functional currency of the Group recognizes gains and losses in the Consolidated Statement of Income. subsidiaries, there is no exposure to currency fluctuation except from receivables or payables originated in local currency mainly corresponding to Price risk VAT. The balances as of 31 December 2015 of VAT were credits for US$ The price realised for the oil produced by the Group is linked to WTI (West 111,000 (US$ 73,000 in 2014) in Argentina, credits for US$ 9,077,000 (US$ Texas Intermediate) and Brent, US dollar denominated international 5,107,000 in 2014) in Chile, and credits for US$ 4,001,000 (payable US$ benchmarks. The market price of these commodities is subject to 1,358,000 in 2014) in Colombia. significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and The Group minimises the local currency positions in Argentina, Colombia and natural gas, market uncertainty, economic conditions and a variety of Chile by seeking to equilibrate local and foreign currency assets and liabilities. additional factors. GeoPark 185 Between October 2014 and February 2016, WTI and Brent have fallen more subsidiary of the Methanex, a Canadian public company (7% of consolidated than 60%, affecting both the Company’s results in 2015 and the Company’s revenues, 6% in 2014 and 7% in 2013). expectations for 2016 (see Note 35). In Colombia, the price of oil is based on Vasconia, a marker broadly used in the operator of the Manati Field and the State owned company. Llanos basin, adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulphur, delivery point and water content. The mentioned companies all have good credit standing and despite the In Brazil, all the hydrocarbons from Manati Field are sold to Petrobras, the concentration of the credit risk, the Directors do not consider there to be a In Chile, the oil price is based on Brent minus certain marketing and quality significant collection risk. discounts such as, inter alia, API quality and others. See disclosure in Note 24. The Company has signed a long-term Gas Supply Contract with Methanex in Chile. The price of the gas sold under this contract is determined based on a Funding and Liquidity risk formula that takes into account various international prices of methanol, In the past, the Group was able to raise capital through different sources of including US Gulf methanol spot barge prices, methanol spot Rotterdam funding including equity, strategic partnerships and financial debt. prices and spot prices in Asia. In Brazil, prices for gas produced in the Manati Field are based on a long-term and over 80% of its total indebtedness maturing in 2020. In addition, the Group has off-take contract with Petrobras. The price of gas sold under this contract is a large portfolio of attractive and largely discretional projects - both oil and gas - in denominated in Brazilian Real and is adjusted annually for inflation pursuant multiple countries with over 20,000 boepd in production. This scale and positioning to the Brazilian General Market Price Index (Indice Geral de Preços do permit GeoPark to protect its financial condition and selectively allocate capital to Mercado), or IGPM. the optimal projects subject to prevailing macroeconomic conditions. The Group is positioned at the end of 2015 with a cash balance of US$ 82,730,000 If oil and methanol prices had fallen by 10% compared to actual prices during However, during 2015 and impacted by the current low oil price environment, the year, with all other variables held constant, post-tax loss for the year would the Company’s Leverage have been higher by US$ 23,940,000 (post tax profit lower by US$ 29,186,000 in 2014 and US$ 27,179,000 in 2013). Ratio and the Interest Coverage did not meet certain thresholds included in the 2020 Bond Indenture. This situation may limit the Company’s capacity to The Group has no price-hedging transaction currently outstanding. The Board incur additional indebtedness, other than permitted debt, as specified in the could consider adopting commodity price hedging measures, when deemed indenture governing the Notes (Note 26). appropriate, according to the size of the business, production levels and market implied volatility. The most significant funding transactions executed in 2015 and 2014 include: The Group’s credit risk relates mainly to accounts receivable where the credit On February 2014, the Group received a gross proceed of US$ 98,000,000 from risks correspond to the recognised values. There is not considered to be any the issuance of new shares. significant risk in respect of the Group’s major customers. On March 2014, GeoPark executed a loan agreement with Itaú BBA In Colombia, the Group have diversified the customer base and for the year International (Itau) for ended 31 December 2015, the Colombian subsidiary made 62.1% of the oil US$ 70,450,000 to finance the acquisition of a working interest in the Manatí sales to Gunvor (a global privately-held company, dedicated to commodities field (Brazil) maturing between 2015 and 2019. trading), 12.6% to Trafigura (one of the world’s leading independent commodity trading and logistics houses) and 9.2% to Petrominerales (a local On March 2015, the Group reached an agreement with Itau to: (i) extend the independent company, dedicated to oil and gas exploration and production), principal payments that were originally due in 2015 (amounting to with Gunvor accounting for 39.1%, Trafigura 7.9% and Petrominerales 5.8% of approximately US$ 15,000,000), which were divided pro-rata during the consolidated revenues for the same period. remaining principal instalments, starting in March 2016 and (ii) increase the variable interest rate equal to the six-month LIBOR + 4.0%. All the oil produced in Chile is sold to ENAP as well as the gas produced by TdF Blocks (15% of total revenue, 28% in 2014 and 40% in 2013), the State owned On December 2015, the Group announced the execution of an offtake and oil and gas company. In Chile, most of gas production is sold to the local prepayment agreement with Trafigura, one of its customers. The prepayment 186 GeoPark 20F agreement provides GeoPark with access to up to US$ 100,000,000 in the form 2015 the gearing ratio at year end is above such range. Measures taken by the of prepaid future oil sales, subject to certain customary covenants. Funds Company in this connection are described in Note 35. committed by Trafigura are available to GeoPark upon request until September 2016 and are to be repaid by the Company through future oil The gearing ratios at 31 December 2015 and 2014 were as follows: deliveries over 2.5 years with a six-month grace period. As of 31 December 2015 no prepayments were requested. Amounts in US$ ´000 Interest rate risk The Group’s interest rate risk arises from long-term borrowings issued at Net Debt Total Equity Total Capital variable rates, which expose the Group to cash flow to interest rate risk. Gearing Ratio 2015 295,943 200,167 496,110 60% 2014 241,921 479,126 721,047 34% The Group does not face interest rate risk on its US$ 300,000,000 Notes which carry a fixed rate coupon of 7.50% per annum. As consequence, the Note 4 accruals and interest payment are no substantially affected to the market Accounting estimates and assumptions interest rate changes. At 31 December 2015 the outstanding long-term borrowing affected by Although these estimates are based on management’s best knowledge of variable rates amounted to US$ 76,178,000, representing 20% of total current events and actions, actual results may differ from them. Estimates and borrowings, which was composed by the loans from Itaú Bank and Banco de judgements are continually evaluated and are based on historical experience Chile that have a floating interest rate based on LIBOR. and other factors, including expectations of future events that are believed to Estimates and assumptions are used in preparing the financial statements. be reasonable under the circumstances. The Group analyses its interest rate exposure on a dynamic basis. Various scenarios are simulated taking into consideration refinancing, renewal of The key estimates and assumptions used in these consolidated financial existing positions, alternative financing and hedging. Based on these statements are noted below: scenarios, the Group calculates the impact on profit and loss of a defined interest rate shift. For each simulation, the same interest rate shift is used for • Cash flow estimates for impairment assessments require assumptions about all currencies. The scenarios are run only for liabilities that represent the major two primary elements - future prices and reserves. Estimates of future prices interest-bearing positions. require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The group´s At 31 December 2015, if 1% is added to interest rates on currency- forecasts for oil and gas revenues are based on prices derived from future denominated borrowings with all other variables held constant, post-tax loss price forecasts amongst industry analysts and own assessments. Estimates of for the year would have been US$ 507,000 higher (post-tax profit lower US$ future cash flows are generally based on assumptions of long-term prices and 312,000 in 2014, nil in 2013). operating and development costs. Capital risk management Given the significant assumptions required and the possibility that actual The Group’s objectives when managing capital are to safeguard the Group’s conditions will differ, management considers the assessment of impairment ability to continue as a going concern in order to provide returns for to be a critical accounting estimate (see Notes 35 and 36). shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, Consistent with others in the industry, the Group monitors capital on the basis engineering and economic data. The estimation of economically recoverable of the gearing ratio. This ratio is calculated as net debt divided by total capital. oil and natural gas reserves and related future net cash flows was performed Net debt is calculated as total borrowings (including ‘current and non-current based on the Reserve Report as of 31 December 2015 prepared by DeGolyer borrowings’ as shown in the consolidated balance sheet) less cash at bank and and MacNaughton, an international consultancy to the oil and gas industry in hand. Total capital is calculated as ‘equity’ as shown in the consolidated based in Dallas. It incorporates many factors and assumptions including: balance sheet plus net debt. - expected reservoir characteristics based on geological, geophysical and engineering assessments; The Group’s strategy is to keep the gearing ratio within a 30% to 45% range, in - future production rates based on historical performance and expected future normal market conditions. Due to the market conditions prevailing during operating and investment activities; GeoPark 187 - future oil and gas prices and quality differentials; Note 5 - assumed effects of regulation by governmental agencies; and Consolidated Statement of Cash Flow - future development and operating costs. Management believes these factors and assumptions are reasonable based year for operating, investing and financing activities and the change in cash The Consolidated Statement of Cash Flow shows the Group’s cash flows for the on the information available to them at the time of preparing the and cash equivalents during the year. estimates. However, these estimates may change substantially as additional data from ongoing development activities and production Cash flows from operating activities are computed from the results for the year performance becomes available and as economic conditions impacting oil adjusted for non-cash operating items, changes in net working capital, and and gas prices and costs change. corporation tax. Tax paid is presented as a separate item under operating • The Group adopts the successful efforts method of accounting. The activities. Management of the Company makes assessments and estimates The following chart describes non-cash transactions related to the regarding whether an exploration asset should continue to be carried Consolidated Statement of Cash Flow: forward as an exploration and evaluation asset not yet determined or when insufficient information exists for this type of cost to remain as an Amounts in US$ ´000 asset. In making this assessment the Management takes professional Increase in asset retirement obligation advice from qualified experts. Financial leases Increase in provisions for other • Oil and gas assets held in property plant and equipment are mainly long-term liabilities depreciated on a unit of production basis at a rate calculated by reference to Purchase of property, plant 2015 985 - - 2014 1,603 - 5,636 2013 7,183 14,133 - proven and probable reserves and incorporating the estimated future cost of and equipment 830 1,382 12,799 developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and equipment, cash flows relating to the • Obligations related to the abandonment of wells once operations are purchase and sale of enterprises to third terminated may result in the recognition of significant obligations. Estimating parties and cash flows from financial lease transactions. Cash flows from the future abandonment costs is difficult and requires management to make financing activities include changes in equity, and proceeds from borrowings estimates and judgments because most of the obligations are many years in and repayment of loans. Cash and cash equivalents include bank overdraft and the future. Technologies and costs are constantly changing as well as political, liquid funds with a term of less than three months. environmental, safety and public relations considerations. The Company has adopted the following criterion for recognising well plugging and Changes in working capital shown in the Consolidated Statement of Cash Flow abandonment related costs: The present value of future costs necessary for are disclosed as follows: well plugging and abandonment is calculated for each area on the basis of a cash flow that is discounted at an average interest rate applicable to Amounts in US$ ´000 Company’s indebtedness. The liabilities recognised are based upon estimated Increase in Prepaid taxes future abandonment costs, wells subject to abandonment, time to Decrease / (Increase) in Inventories 2015 (16,611) 2,752 abandonment, and future inflation rates. Decrease / (Increase) in Trade receivables 22,470 Decrease / (Increase) in Prepayments • From time to time, the Company may be subject to various lawsuits, claims and other receivables and Other assets 405 and proceedings that arise in the normal course of business, including Decrease in Trade and other payables employment, commercial, environmental, safety and health matters. For example, from time to time, the Company receives notice of environmental, health and safety violations. Based on what the Management of the Company currently knows, it is not expected any material impact on the financial statements. (33,120) (24,104) 2014 (3,310) (410) 13,791 2013 (4,283) (4,166) (10,357) 12,569 (12,097) 10,543 (13,330) (493) (32,629) 188 GeoPark 20F Note 6 Segment information performance to be more comparable with other companies in the market and also to better follow up the performance of the business. This change impacts the segment information because gross profit or loss is no longer shown but Operating segments are reported in a manner consistent with the internal no impact is generated in the measure of segment profit and loss. reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing The Executive Committee assesses the performance of the operating performance of the operating segments, has been identified as the Executive segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined Committee. This committee is integrated by the CEO, COO, CFO and managers as profit for the period before net finance cost, income tax, depreciation, in charge of the Geoscience, Operations, Corporate Governance, Finance and amortization, certain non-cash items such as impairments and write-offs of People departments. This committee reviews the Group’s internal reporting in unsuccessful efforts, accrual of share-based payment and other non recurring order to assess performance and allocate resources. Management has events. Operating Netback is equivalent to Adjusted EBITDA before cash determined the operating segments based on these reports. expenses included in Administrative, Geological and Geophysical and Other operating expenses. Other information provided, except as noted below, to the The committee considers the business from a geographic perspective. As from Executive Committee is measured in a manner consistent with that in the 2015, the committee has changed the disclosure of certain elements of financial statements. Segment areas (geographical segments): Amounts in US$ ´000 2015 Net revenue - Sale of crude oil - Sale of gas Production and operating costs - Royalties - Transportation costs - Share-based payment - Other costs Operating (loss) / profit Adjusted EBITDA Depreciation Impairment loss Write-off Total assets Employees (average) Employees at year end Argentina Brazil Colombia Peru Chile Corporate Total 32,388 131,897 955 131,897 597 597 - (1,448) (34) (2) (197) (1,215) (2,350) (684) 31,433 (8,056) (2,998) - - (5,058) 6,639 20,460 (199) (13,568) - - - - 3,181 114,974 - (48,534) (8,150) (2,068) (234) (38,082) (37,227) 66,736 (52,434) (45,059) (4,333) 153,071 - - - - - - - - 44,808 29,180 15,628 (28,704) (1,973) (2,441) (132) (24,158) - - - - - - - - 209,690 162,629 47,061 (86,742) (13,155) (4,511) (563) (68,513) (6,719) (180,264) (12,570) (232,491) (6,520) (183) (6,022) 73,787 (129) (39,227) - - 4,287 (104,515) (25,751) 381,143 - - - 47,143 (105,557) (149,574) (30,084) 703,799 93 90 11 12 130 133 16 11 153 106 - - 403 352 GeoPark 189 Amounts in US$ ´000 2014 Net revenue - Sale of crude oil - Sale of gas Production costs - Royalties - Transportation costs - Share-based payment - Other costs Operating (loss) / profit Adjusted EBITDA Depreciation Impairment loss Write-off Total assets Employees (average) Employees at year end 2013 Net revenue - Sale of crude oil - Sale of gas Production costs - Royalties - Transportation costs - Share-based payment - Other costs Operating (loss) / profit Adjusted EBITDA Depreciation Write-off Total assets Employees (average) Employees at year end Argentina Brazil Colombia Peru Chile Corporate Total 1,308 1,304 4 (550) (241) (87) (433) 211 (4,321) (816) 35,621 246,085 1,541 246,054 34,080 (8,148) (2,794) - - (5,354) 10,658 22,637 31 (80,953) (12,354) (4,663) (423) (63,513) 67,212 130,209 (229) (11,613) (51,584) - - (9,430) (1,564) - - - - - - - - (2,419) (2,425) - - - 145,720 118,203 27,517 (41,768) (6,777) (6,784) (763) (27,444) 11,733 76,420 - - - - - - - - (11,019) 428,734 367,102 61,632 (131,419) (22,166) (11,534) (1,619) (96,100) 71,844 (5,948) 220,077 (37,077) (25) (100,528) - (28,772) 541,481 - - (9,430) (30,367) 74,143 1,039,116 151,770 263,070 4,813 10 12 121 133 4 14 208 197 - (31) 3,839 100 100 1,538 1,532 6 (287) (194) (204) (347) 458 (225) - 7,977 97 98 - - - - - - - - 179,324 179,324 - (72,479) (9,661) (4,733) (905) (57,180) 38,811 82,611 (39,406) (3,258) 259,421 3 4 107 109 (1,942) 166 (3,107) (3,037) (2) - 29,222 - - - - - - - - - - (12,908) 443 456 338,353 315,435 22,918 (111,296) (17,239) (11,392) (2,552) (80,113) 83,964 (8,835) 167,253 (96) - (69,968) (10,962) 72,532 846,415 - - 391 404 - - - - - - - - - - - - - - - 157,491 134,579 22,912 (38,530) (7,384) (6,455) (1,300) (23,391) 63,110 96,348 (30,239) (7,704) 477,263 184 193 Approximately 22% of capital expenditure was allocated to Chile (66% in 2014 and 63% in 2013), 66% was allocated to Colombia (29% in 2014 and 37% in 2013) and 12% was allocated to Brazil (5% in 2014, nil in 2013). The capital expenditure referred does not include total consideration for M&A activities. 190 GeoPark 20F A reconciliation of total Operating netback to total profit before income tax is Note 9 provided as follows: Amounts in US$ ´000 Operating netback Administrative expenses Geological and geophysical expenses Adjusted EBITDA for reportable segments Depreciation(a) Share-based payment Impairment and write-off of unsuccessful efforts Others(b) Operating (loss) profit Financial costs Foreign exchange loss (Loss) Profit before tax Depreciation 2015 2014 2013 Amounts in US$ ´000 118,027 274,509 214,682 Oil and gas properties (30,590) (13,650) (40,340) (14,092) (39,572) Production facilities and machinery (7,857) Furniture, equipment and vehicles 73,787 220,077 (105,557) (100,528) (8,223) (8,373) 167,253 (69,968) (9,167) Buildings and improvements Depreciation of property, plant and equipment(*) (179,658) (39,797) (10,962) Productive assets Related to: (12,840) (232,491) (35,655) (33,474) (301,620) 465 71,844 (27,622) (23,097) 21,125 6,808 83,964 (33,115) (761) 50,088 Administrative assets Depreciation total(*) 2015 84,849 15,467 2,850 874 2014 89,651 9,621 1,862 523 2013 59,234 9,341 964 661 104,040 101,657 70,200 100,316 3,724 99,360 2,297 104,040 101,657 68,579 1,621 70,200 (*) Depreciation without considering capitalised costs for oil stock included in Inventories. (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. Note 10 Staff costs and Directors Remuneration Note 7 Net Revenue Amounts in US$ ´000 Sale of crude oil Sale of gas Number of employees at year end Amounts in US$ ‘000 Wages and salaries 2015 162,629 47,061 2014 367,102 61,632 2013 Share-based payments (Note 29) 315,435 Share-based payments – 22,918 Cash awards (Note 29) 209,690 428,734 338,353 Social security charges Director’s fees and allowance Note 8 Production and operating costs Amounts in US$ ´000 Well and facilities maintenance Staff costs (Note 10) Share-based payment (Notes 10 and 29) Royalties Consumables Transportation costs Equipment rental Safety and Insurance costs Gas plant costs Field camp Non operated blocks costs Other costs 2015 19,974 17,999 563 13,155 8,591 4,511 3,517 3,239 2,878 2,645 2,127 7,543 2014 25,475 16,112 1,619 22,166 16,157 11,534 7,563 5,733 3,277 5,932 9,730 6,121 Recognised as follows: Production and operating costs Geological and geophysical expenses 2013 Administrative expenses 20,662 11,650 2,552 Board of Directors’ and key managers’ remuneration Salaries and fees Share-based payments Other benefits in kind 17,239 14,855 11,392 7,139 4,843 3,217 4,805 5,635 7,307 86,742 131,419 111,296 2015 352 2014 456 2013 404 40,574 8,223 41,593 9,178 29,504 8,362 - 6,197 1,239 (805) 6,597 1,998 805 5,291 1,426 56,233 58,561 45,388 18,562 11,336 26,335 56,233 17,731 12,939 27,891 58,561 14,202 7,676 23,510 45,388 6,549 6,544 167 11,003 3,314 130 7,702 2,971 742 13,260 14,447 11,415 GeoPark 191 Directors’ Remuneration Gerald O’Shaughnessy James F. Park Pedro Aylwin(2) Peter Ryalls(3) Juan Cristóbal Pavez(4) Carlos Gulisano(5) Steven J. Quamme(6) Robert Bedingfield Executive Directors’ Fees US$ 200,000 US$ 450,000 Executive Directors’ Bonus(7) US$ 75,000 US$ 325,000 - - - - - - - - - - - - Non-Executive Directors’ Fees (in US$) - - - US$ 108,000 US$ 99,000 US$ 99,000 US$ 33,322 US$ 70,000 Director Fees Paid in Shares No. of Shares(1) - - - 20,343 20,343 20,343 5,811 17,042 Cash Equivalent Total Remuneration US$ 275,000 US$ 775,000 - US$ 198,029 US$ 189,029 US$ 189,029 US$ 64,207 US$ 140,025 1 Only 8,285 shares of the 83,882 shares paid as Director Fees were not issued during 2015 (see Note 29). 2 Pedro Aylwin has a service contract that provides for him to act as Manager of Corporate Governance so he resigned his fees as Director. 3 Technical Committee Chairman. 4 Compensation Committee Chairman. 5 Nomination Committee Chairman. 6 Audit Committee Chairman until his resignation on 19 March 2015. Afterwards the Chairman is Robert Bedingfield. 7 On 10 December 2015, 123,839 shares were allocated to the payment of the Bonus. The non-executive Directors annual fees correspond to US$ 80,000 to be settled in cash and US$ 100,000 to be settled in stocks, paid quarterly in equal 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. A Director who serves as a member of any Board Committees shall receive an annual fee of US$ 10,000. Total payment due shall be calculated in an aggregate basis for Directors serving in more than one Committee. The Chairman fee shall not be added to the member´s fee for the same Committee. Payments of Chairmen and Committee members´ fees shall be made quarterly in arrears and settled in cash only. During the first half of 2015, a decrease of 20% in the compensation program for the services of the non-executive Directors was approved. Stock Awards to Executive Directors The following Stock Options were issued to Executive Directors during 2012: Name Gerald O’Shaughnessy James F. Park N° of Underlying Common Shares 270,000 450,000 Grant Date 23 Nov 2012 23 Nov 2012 Exercise Price (US$) 0.001 0.001 Earliest Exercise Date 23 Nov 2015 23 Nov 2015 On 30 November 2015, the 720,000 shares were issued. 192 GeoPark 20F Note 11 Geological and geophysical expenses Note 14 Financial costs Amounts in US$ ´000 Staff costs (Note 10) Share-based payment (Notes 10 and 29) Allocation to capitalised project Other services Amortisation of other long-term liabilities related to unsuccessful efforts Recovery of abandonments costs 2015 10,557 779 (598) 3,093 - - 2014 11,712 1,227 (2,317) 2,380 2013 6,451 1,225 Amounts in US$ ´000 Financial expenses Interest and amortisation 2015 2014 2013 (2,437) of debt issue costs 30,543 29,466 25,208 1,406 Less: amounts capitalised on qualifying assets - - (600) (753) Bank charges and other financial costs Unwinding of long-term (637) 4,443 (3,112) 2,672 (1,313) 2,519 13,831 13,002 5,292 liabilities (Note 27) 2,575 1,972 1,523 Note 12 Administrative expenses Amounts in US$ ´000 Staff costs (Note 10) Share-based payment (Notes 10 and 29) Consultant fees Office expenses Travel expenses Director’s fees and allowance New projects Other administrative expenses 2015 18,215 6,881 4,115 2,535 1,497 1,238 559 2,431 2014 20,366 5,527 6,791 3,190 2,052 1,998 2,798 3,145 2013 16,694 5,390 6,424 2,652 1,258 1,426 3,720 7,398 Notes GeoPark Fell SpA cancellation costs Financial income Interest received - - 8,603 (1,269) 35,655 (3,376) 27,622 (3,425) 33,115 Note 15 Tax reforms in Colombia and Chile Colombia The Colombian Congress approved a Tax Reform in December 2014. This reform had introduced a temporary net wealth tax assessed on net equity on domestic and foreign legal entities, kept the rate of the income tax on equality 37,471 45,867 44,962 (Enterprise contribution on equality, “CREE” for its Spanish acronym) at 9%, and applied a CREE surcharge until 2018, among other changes. Note 13 Selling expenses Amounts in US$ ´000 Transportation Selling taxes Storage Allowance for doubtful accounts The net wealth tax (NWT) assessed on net equity applied for tax years 2015 through 2017 for domestic and foreign entities that hold any wealth in Colombia, directly or indirectly, via permanent establishments (PEs) or branches. 2015 4,760 440 11 - 2014 2013 In the case of foreign or domestic individuals, the NWT would apply until 2018. 23,106 16,181 433 148 741 406 665 NWT applied at progressive rates ranging from 1.15% in 2014; 1% in 2015 and decreased to 0.4% in 2016 and finally would disappear in 2017, for - corporate taxpayers. NWT paid is not deductible or creditable for Colombian 5,211 24,428 17,252 income tax purposes. The Reform also extended the current 9% CREE tax rate, which was scheduled to decrease to 8% in 2016. Also, it introduced a new CREE surcharge, beginning in 2015, from 5% in 2015, 6% in 2016, and 8% in 2017 to 9% in 2018. Therefore, the accumulated corporate income tax rate will rise to 43% in 2018. The Company considered the effects of this rate increase in the deferred income tax calculation. In addition, in December 2015, Colombia’s government announced its plan for a tax reform to be submitted to Congress in March 2016. The main proposed changes included in the project are the following: GeoPark 193 • Unification between Income Tax and CREE, resulting in a “new income tax” Under current Bermuda law, the Company is not required to pay any taxes in with a rate between 30% and 35%; • Elimination of NWT; Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any • Incorporation of dividend distribution withholding tax, with a rate between taxes being imposed, they will be exempt from taxation in Bermuda until 10% and 15%; • Increase of VAT rate from 16% to 19% March 2035. Income tax rates in those countries where the Group operates (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 39%. All these measures, if approved, will have effect for 2017 fiscal year onwards. The Group has significant tax losses available which can be utilised against future taxable profit in the following countries: Chile The Chilean Congress approved a reform to the income tax law in September Amounts in US$ ´000 2014. Under this reform the income tax rate increased from 20% in 2013 to 21% in 2014, 22.5% in 2015, 24% in 2016, 25.5% in 2017 and 27% in 2018. The operating subsidiaries that GeoPark controls in Chile, which are GeoPark TdF S.A., GeoPark Fell SpA and GeoPark Magallanes Limitada, are not affected Argentina Chile(1) Brazil(1) Total tax losses at 31 December by such income tax reform since they are covered by the tax treatment (1) Taxable losses have no expiration date. established in the Special contract of operations (“CEOPs”). 2015 3,834 2014 6,707 2013 10,259 209,910 105,293 15,935 - 3,191 - 213,744 115,191 26,194 Note 16 Income tax Amounts in US$ ´000 Current tax Deferred income tax (Note 17) 2015 7,262 (24,316) (17,054) At the balance sheet date deferred tax assets in respect of tax losses in Argentina and in certain Companies in Chile have not been recognised as there is insufficient evidence of future taxable profits before the statute of limitation of these tax losses causes them to expire. 2014 2013 Expiring dates for tax losses accumulated at 31 December 2015 are: 23,574 13,337 (18,379) 5,195 15,154 1,817 Expiring date Amounts in US$ ´000 2016 2017 2020 986 1,301 1,547 The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows: Amounts in US$ ´000 (Loss) Profit before tax Tax losses from non-taxable jurisdictions Taxable (loss) profit Income tax calculated at domestic tax rates applicable to (losses) profits 2015 (301,620) 2014 21,125 2013 50,088 Note 17 Deferred income tax The gross movement on the deferred income tax account is as follows: 15,852 (285,768) 5,010 26,135 14,348 64,436 Amounts in US$ ´000 Deferred tax at 1 January Acquisition of subsidiaries Reclassification(1) Currency translation differences 328 Income statement credit (5,146) Deferred tax at 31 December 1,988 2015 3,130 - (6,061) (3,694) 24,316 17,691 2014 (9,729) (3,132) (2,123) (265) 18,379 3,130 - - (1) Corresponds to differences between income tax provision and the final tax return presented. 3,973 15,154 in the respective countries (62,589) 7,606 14,011 Tax losses where no deferred income tax is recognised Effect of currency translation on tax base Expiration of tax loss carry-forwards Changes in the income tax rate (Note 15) 16,325 6,776 - 625 148 (8,128) - 691 Non recoverable tax loss carry-forwards Non-taxable results(1) Income tax (1) Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities. (17,054) 15,537 5,195 4,878 6,272 - 194 GeoPark 20F The breakdown and movement of deferred tax assets and liabilities as of 31 December 2015 and 2014 are as follows: Amounts in US$ ´000 Deferred tax assets Difference in depreciation rates and other Taxable losses Total 2015 Total 2014 At the beginning Currency translation (Charged) / credited of year differences to net profit At end of year 1,434 31,761 33,195 13,358 - (3,694) (3,694) (423) 30,314 (25,169) 5,145 20,260 31,748 2,898 34,646 33,195 At the beginning Acquisition of (Charged) / credited Currency translation Amounts in US$ ´000 Deferred tax liabilities Difference in depreciation rates and other Taxable losses Total 2015 Total 2014 of year subsidiaries to net profit Reclassification(1) differences At end of year (34,717) 4,652 (30,065) (23,087) - - - (3,132) 10,110 9,061 19,171 (1,881) (1,409) (4,652) (6,061) (2,123) - - - 158 (26,016) 9,061 (16,955) (30,065) (1) Corresponds to differences between income tax provision and the final tax return presented. Note 18 Earnings per share Amounts in US$ ‘000 except for shares Numerator: (Loss) Profit for the year attributable to owners Denominator: Weighted average number of shares used in basic EPS (Losses) Earnings after tax per share (US$) – basic Amounts in US$ ‘000 except for shares Weighted average number of shares used in basic EPS Effect of dilutive potential common shares Stock awards at US$ 0.001 Weighted average number of common shares for the purposes of diluted earnings per shares Earnings after tax per share (US$) – diluted (1) For the year ended 31 December 2015, there were 1,032,279 of potential shares that could have a dilutive impact but were considered antidilutive due to negative earnings. 2015 (234,031) 57,759,001 (4.05) 2015(*) 57,759,001 2014 8,085 2013 22,521 56,396,812 43,603,846 0.14 2014 0.52 2013 56,396,812 43,603,846 - 2,443,600 2,928,203 57,759,001 (4.05) 58,840,412 0.14 46,532,049 0.48 GeoPark 195 Note 19 Property, plant and equipment Amounts in US$ ´000 Cost at 1 January 2013 Additions Disposals Write-off / Impairment loss Transfers Cost at 31 December 2013 Additions Acquisition of subsidiaries Currency translation differences Disposals Write-off / Impairment loss Transfers Cost at 31 December 2014 Additions Currency translation differences Disposals Write-off / Impairment loss Transfers Cost at 31 December 2015 Depreciation and write-down at 1 January 2013 Depreciation Depreciation and write-down at 31 December 2013 Depreciation Disposals Currency translation differences Depreciation and write-down at 31 December 2014 Depreciation Disposals Currency translation differences Depreciation and write-down at 31 December 2015 Carrying amount at 31 December 2013 Carrying amount at 31 December 2014 Carrying amount at 31 December 2015 196 GeoPark 20F Furniture, Production Oil & gas equipment facilities and Buildings and Construction properties and vehicles machinery improvements in progress 344,371 9,367 (553) - 140,075 493,260 3,013 112,646 (21,941) - (9,430) 172,399 749,947 (4,640)(1) (27,522) (241) (128,956) 60,404 648,992 (98,156) (59,234) (157,390) (89,651) - 6,602 (240,439) (84,849) - 4,115 3,576 2,060 (22) - 117 5,731 3,367 201 (122) (353) - 3,233 12,057 954 (182) (13) - 929 13,745 (1,836) (964) (2,800) (1,862) 278 (65) (4,449) (2,850) 8 (26) 86,949 512 (15,870)(*) - 27,246 98,837 11 - - (666) - 13,464 111,646 - (2,577) (1,685) (13,242) 30,690 124,832 (26,336) (9,341) (35,677) (9,621) 151 - (45,147) (15,467) - - 3,198 - - - 3,820 7,018 490 - - - - 2,019 9,527 272 (92) (84) - 895 10,518 (1,060) (661) (1,721) (523) - - (2,244) (874) 15 (92) (321,173) (7,317) (60,614) (3,195) 54,025 89,976 - - (103,572) 40,429 136,232 - - - - (117,236) 59,425 36,543 - - (7,376) (58,769) 29,823 - - - - - - - - - - - Exploration and evaluation assets(2) 93,106 133,301 - (10,962)(a) (67,686) 147,759 97,919 - (988) - (30,367)(b) (73,879) 140,444 12,299 (1,510) - (30,084)(c) (34,149) 87,000 - - - - - - - - - - - Total 585,225 235,216 (16,445) (10,962) - 793,034 241,032 112,847 (23,051) (1,019) (39,797) - 1,083,046 45,428 (31,883) (2,023) (179,658) - 914,910 (127,388) (70,200) (197,588) (101,657) 429 6,537 (292,279) (104,040) 23 3,997 (392,299) 335,870 2,931 63,160 5,297 40,429 147,759 595,446 509,508 7,608 66,499 7,283 59,425 140,444 790,767 327,819 6,428 64,218 7,323 29,823 87,000 522,611 (*) During 2013, the Company entered into a finance lease for which it has transferred a substantial portion of the risk and rewards of some assets which Amounts in US$ ´000 Exploration wells at 31 December 2013 had a book value of US$ 14,100,000. In 2014, the finance lease finalized when Additions the purchase option on the assets subject to the agreement was exercised by Write-offs the lessee. (1) Corresponds to the effect of change in estimate of assets retirement obligations in Colombia. Transfers Exploration wells at 31 December 2014 Additions Write-offs Transfers (2) Exploration wells movement and balances are shown in the table below; seismic and other exploratory assets amount to US$ 64,094,000 (US$ Exploration wells at 31 December 2015 Total 29,918 87,741 (24,339) (52,815) 40,505 16,067 (6,280) (27,386) 22,906 99,939,000 in 2014 and US$ 117,841,000 in 2013). As of 31 December 2015, there were seven exploratory wells that have been capitalised for a period over a year amounting to US$ 19,273,000 and three exploratory wells that have been capitalised for a period less than a year amounting to US$ 3,633,000. (a) Corresponds to the cost of five unsuccessful exploratory wells: two of them in Chile (one in Fell Block and one in Tranquilo Block) and three of them in Colombia (one well in Cuerva Block, one well in each of the non-operated blocks, Arrendajo and Llanos 32). (b) Corresponds to the cost of ten unsuccessful exploratory wells: eight of them in Chile (three in Flamenco Block, two in Fell Block, two in Tranquilo Block and one in Campanario Block) and two of them in Colombia (two in the non- operated Arrendajo Block). The charge also includes the loss generated by the write-off of the remaining seismic cost for Otway and Tranquilo Blocks, registered in previous years. (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. GeoPark 197 Note 20 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of 31 December 2015: 100% GeoPark Latin America Limited 100% GeoPark Latin America Limited Agencia en Chile GeoPark Limited (Bermuda) 100% 1% 99.9% 99.9% 99.9% GeoPark Argentina Limited – Bermuda GeoPark Latin America Coöperatie U.A. (The Netherlands) GeoPark Peru Coöperatie U.A. (The Netherlands) GeoPark Brazil Coöperatie U.A. (The Netherlands) 100% 80% GeoPark Argentina Limited - Argentinean Branch GeoPark Colombia Coöperatie U.A. (The Netherlands) 20% LG International 99.9% GeoPark Brazil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) 100% GeoPark Colombia SAS (Colombia) 80% 99.9% 100% LG International 20% GeoPark Chile S.A. (Chile) GeoPark S.A. (Chile) GeoPark Colombia S.A. (Chile) 99.9% GeoPark S.A.C. (Peru) 14% 86% 100% 99% GeoPark TdF S.A. (Chile) GeoPark Fell SpA. (Chile) GeoPark Magallanes Limitada (Chile) 99.9% 99.9% GeoPark Peru S.A.C. (Peru) GeoPark Operadora del Peru S.A.C. (Peru) (*) LGI is not a subsidiary, it is Non-controlling interest. 198 GeoPark 20F Details of the subsidiaries and joint operations of the Company are set out below: Name and registered office Ownership interest Subsidiaries GeoPark Argentina Limited – Bermuda GeoPark Argentina Limited – Argentinean Branch GeoPark Latin America Limited 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 Brazil S.p.A. (Chile) GeoPark Latin America Coöperatie U.A. (The Netherlands) 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 Coöperatie U.A. (The Netherlands) GeoPark Brazil Coöperatie U.A. (The Netherlands) GeoPark Colombia E&P S.A.(Panama) Tranquilo Block (Chile) Flamenco Block (Chile) Campanario Block (Chile) Isla Norte Block (Chile) Llanos 17 Block (Colombia) Yamu/Carupana Block (Colombia) Llanos 34 Block (Colombia) Llanos 32 Block (Colombia) CPO-4 Block (Colombia) Puelen (Argentina) Sierra del Nevado (Argentina) CN-V (Argentina) Manati Field (Brazil) Joint operations (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 in all blocks. (f ) On 17 December 2014, the ANP approved the transfer of cession of rights of the Block from Rio das Contas to GeoPark Brazil. On 31 January 2015, both companies, Rio das Contas and GeoPark Brazil were merged into GeoPark Brazil. 100% 100%(a) 100% 100%(a) 100%(a)(b) 100%(a)(f ) 80%(a)(c) 80%(a)(c) 80%(a)(c) 68.8%(a)(d) 100%(a) 100%(a)(h) 100%(a)(b) 100% 100%(a)(c) 100%(a) 100%(a) 100%(a) 100% 100% 100%(b) 50%(e) 50%(e) 50%(e) 60%(e) 36.84% 89.5%/100%(e) 45%(e) 10% 50%(e) 18% 18% 50% 10% GeoPark 199 Movements on the Group provision for impairment are as follows: Amounts in US$ ´000 At 1 January Foreign exchange income Allowance for doubtful accounts (Note 13) 2015 774 (178) - 596 2014 33 - 741 774 2015 14,486 4,844 1,037 2014 8,884 4,834 994 20,367 14,712 19,195 1,172 20,367 2015 2,120 2,144 4,264 The credit period for trade receivables is 30 days. The maximum exposure to 13,459 credit risk at the reporting date is the carrying value of each class of receivable. 1,253 The Group does not hold any collateral as security related to trade receivables. 14,712 The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature. Note 24 Financial instruments by category 2014 6,719 1,813 Amounts in US$ ´000 8,532 Assets as per statement of financial position Trade receivables To be recovered from co-venturers (Nota 32) Other financial assets(*) Cash at bank and in hand Loans and receivables 2015 2014 13,480 4,634 14,424 82,730 36,917 5,931 12,979 127,672 115,268 183,499 2014 36,917 (*) Other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations. 36,917 Non current financial assets also include a non current account receivable. 5,931 Current financial assets corresponds to short term investments with original - maturities up to three months. 8,411 14,342 51,259 Amounts in US$ ´000 Liabilities as per statement of financial position 50,910 Trade payables 349 Payables to related parties (Note 32) 51,259 To be paid to co-venturers (Note 32) Borrowings Other financial liabilities at amortised cost 2015 2014 25,906 21,045 113 64,457 16,591 1,335 378,673 369,593 425,737 451,976 Note 21 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 22 Inventories Amounts in US$ ´000 Crude oil Materials and spares Note 23 Trade receivables and Prepayments and other receivables Amounts in US$ ´000 Trade receivables To be recovered from co-venturers (Note 32) Related parties receivables (Note 32) Prepayments and other receivables Total Classified as follows: Current Non current Total 2015 13,480 13,480 4,634 38 6,605 11,277 24,757 24,537 220 24,757 Trade receivables that are aged by less than three months are not considered impaired. As of 31 December 2015, trade receivables of US$ 51,000 (US$ 6,092 in 2014) were aged by more than 3 months, but not impaired. These relate to customers for whom there is no recent history of default. There are no balances due between 31 days and 90 days as of 31 December 2015 and 2014. 200 GeoPark 20F Credit quality of financial assets Financial liabilities - contractual undiscounted cash flows The credit quality of financial assets that are neither past due nor impaired can The table below analyses the Group’s financial liabilities into relevant maturity be assessed by reference to external credit ratings (if available) or to historical groupings based on the remaining period at the balance sheet to the information about counterparty default rates: contractual maturity date. The amounts disclosed in the table are the Amounts in US$ ´000 Trade receivables Counterparties with an external credit rating (Moody’s) Ba2 B3 Baa3 Counterparties without an external credit rating Group1(*) Total trade receivables 2015 2014 contractual undiscounted cash flows. Between Between Less than 1 and 2 2 and 5 - 11,793 Amounts in US$ ´000 1 year years years 5,834 6,315 - At 31 December 2015 11,292 Borrowings Trade payables 42,865 25,906 44,419 391,988 - - 1,331 13,480 13,832 Payables to 36,917 related parties 1,561 70,332 1,561 25,094 45,980 417,082 Over 5 years - - - - (*) Group 1 – existing customers (more than 6 months) with no defaults in the past. All trade receivables are denominated in US Dollars, except in Brazil where are denominated in Brazilian Real. Cash at bank and other financial assets(1) Amounts in US$ ´000 Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services) A1 A2 Aa2 A3 Ba1 Baa1 Baa3 Caa2 BBB- BRC 1+ Counterparties without an external credit rating Total (1) The remaining balance sheet item ‘cash at bank and in hand’ corresponds to cash on hand amounting to US$ 10,000 (US$ 112,000 in 2014). (US$ 0.001 each) Amount in US$ At 31 December 2014 Borrowings Trade payables Payables to related parties 41,124 64,457 40,342 109,152 322,500 - - 1,325 1,325 17,226 - - 2015 2014 106,906 41,667 126,378 322,500 862 17 Note 25 46,272 22,621 Share capital - - - 40,402 42,218 21,145 - Issued share capital Common stock (amounts in US$ ‘000) The share capital is distributed as follows: 2015 59 2014 58 Common shares, of nominal US$ 0.001 59,535,614 57,790,533 Total common shares in issue 59,535,614 57,790,533 994 Authorised share capital 13,142 US$ per share 140,539 Number of common shares 460 1,675 3,705 105 29,425 160 56 - 14,424 97,144 0.001 0.001 5,171,949,000 5,171,949,000 5,171,949 5,171,949 Details regarding the share capital of the Company are set out below: Common shares As of 31 December 2015, the outstanding common shares confer the following rights on the holder: • the right to one vote per share; • ranking pari passu, the right to any dividend declared and payable on common shares; GeoPark 201 GeoPark common shares history Shares outstanding at the end of 2013 IPO Stock awards Buyback program Shares outstanding at the end of 2014 Stock awards Stock awards Stock awards Buyback program Shares outstanding at the end of 2015 Shares issued Shares share, including over-allotment option. Gross proceeds from the offering closing US$(`000) totalled US$ 98,000,000. Date (millions) (millions) Closing Feb 2014 Feb 2014 Dec 2014 Nov 2015 Dec 2015 Dec 2015 Dec 2015 14.0 0.0 (0.1) 1.5 0.5 0.1 (0.4) 43.9 57.9 57.9 57.8 57.8 59.3 59.8 59.9 59.5 59.5 Buyback Program On 19 December 2014, the Company approved a program to repurchase up to US$ 10,000,000 of common shares, par value US$ 0.001 per share of the Company (the “Repurchase Program”). The Repurchase Program began on 19 December 2014 and was resumed on 14 April 2015 and then on 10 June 2015, expiring on 18 August 2015. The Shares repurchased will be used to offset, in part, any expected dilution effects resulting from the Company’s employee incentive schemes, including grants under the Company’s Stock Award Plan and the Limited Non-Executive Director Plan. During 2015 and 2014, the Company purchased 370,074 and 73,082 common shares for a total amount of US$ 1,615,000 and US$ 388,000, respectively. These transactions had no impact on the Company’s results. 44 58 58 58 58 59 60 60 59 59 Stock Award Program and Other Share Based Payments On 29 October 2013, the Company put into place an irrevocable, non- Note 26 Borrowings discretionary share purchase program for the purchase of its common shares for the account of the EBT. This Purchase Program expired on 31 December Amounts in US$ ´000 2015 2014 2013. The common shares purchased under the program will be used to satisfy future awards under the incentive schemes. During 2013, the Company purchased 50,000 common shares for a total amount of US$ 440,000. Under the stock awards programs and other share based payments, during 2013, 60,000 new common shares were issued, pursuant to a consulting Outstanding amounts as of 31 December Notes GeoPark Latin America Agencia en Chile(a) Banco Itaú(b) Banco de Crédito e Inversiones(c) Banco de Chile(d) agreement for services rendered to GeoPark Limited generating a share Classified as follows: premium of US$ 506,630. Current Non current 302,495 69,142 - 7,036 300,963 68,540 90 - 378,673 369,593 35,425 343,248 27,153 342,440 On 12 November 2015 and 22 December 2015, 817,600 and 478,000 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), The fair value of these financial instruments at 31 December 2015 amounts to generating a share premium of US$ 11,359,000 and US$ 3,577,000, US$ 352,410,000 (US$ 360,181,000 in 2014). The fair values are based on cash respectively. On 17 September 2013, 295,599 common shares were allotted to flows discounted using a rate based on the borrowing rate of 7.51% (2014: the trustee of the EBT, generating a share premium of US$ 3,441,689. 7.40%) and are within level 2 of the fair value hierarchy. On 30 November 2015 720,000 new common shares were issued to the Executive Directors, generating a share premium of US$ 7,309,000. (a) During February 2013, the Company successfully placed US$ 300,000,000 notes which were offered under Rule 144A and Regulation S exemptions of the United States Securities laws. During 2015, the Company issued 99,555 (2,301 in 2014 and 10,430 in 2013) shares to Non-Executive Directors in accordance with contracts as compensation, The Notes, issued by the Company’s wholly-owned subsidiary GeoPark generating a share premium of US$ 486,692 (US$ 22,413 in 2014 and US$ 100,988 Latin America Limited Agencia en Chile (“the Issuer”), were priced at in 2013). The amount of shares issued is determined considering the contractual 99.332% and carry a coupon of 7.50% per annum (yield 7.625% per compensation and the fair value of the shares for each relevant period. annum). Final maturity of the notes will be 11 February 2020. The Notes are IPO guaranteed by GeoPark Limited and GeoPark Latin America Cooperatie U.A. and are secured with a pledge of all of the equity interests of the On 7 February 2014, the SEC declared effective the Company’s registration Issuer in GeoPark Chile S.A. and GeoPark Colombia S.A. and a pledge of statement upon which 13,999,700 shares were issued at a price of US$ 7 per certain intercompany loans. The debt issuance cost for this transaction 202 GeoPark 20F amounted to US$ 7,637,000. The indenture governing our Notes due 2020 As of the date of these consolidated financial statements, the Group has includes incurrence test covenants that provides among other things, that, available credit lines for over US$ 37,000,000. the Debt to EBITDA ratio should not exceed 2.5 times and the EBITDA to Interest ratio should exceed 3.5 times. As of the date of these consolidated financial statements, the Company’s Debt to EBITDA ratio was 5.1 times Note 27 and the EBITDA to Interest ratio was 2.4 times, primarily due to the lower Provisions and other long-term liabilities oil prices that impacted the Company’s EBITDA generation. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Company’s capacity to incur Asset retirement Deferred additional indebtedness, as specified in the indenture governing the Notes. Amounts in US$ ´000 obligation Incurrence covenants as opposed to maintenance covenants must be At 1 January 2014 tested by the Company before incurring additional debt or performing Addition to provision 24,166 1,603 certain corporate actions including but not limited to dividend payments, Recovery of restricted payments and others, (other than in each case, certain specific abandonments costs (1,317) exceptions). As of the date of these consolidated financial statements, the Acquisition Company is in compliance of all the indenture’s provisions. (b) 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 of subsidiaries Foreign currency translation Exchange difference interest in the Manatí field in Brazil. The inte-rest rate applicable to this loan Amortisation is LIBOR plus 3.9% per annum. The interest will be paid semi-annually; Unwinding of discount principal will be cancelled semi-annually with a year grace period. The debt At 31 December 2014 issuance cost for this transac-tion amounted to US$ 3,295,000. The facility Addition to provision agreement includes customary events of default, and requi-res the Brazilian Recovery of 6,862 (1,170) 1,170 - 1,972 33,286 985 subsidiary to comply with customary covenants, including the maintenance abandonments costs (5,229) of a ratio of net debt to EBITDA of up to 3.5x for the first two years and up to Foreign currency 3.0x thereafter. The credit facility also limits the borrower’s ability to pay translation dividends if the ratio of net debt to EBITDA is greater than 2.5x. As of the Exchange difference (2,469) 2,469 Income 6,204 - - - - - (468) - 5,736 - - - - date of these consolidated financial statements, the Company has complied Amortisation - (703) Other 2,706 5,934 - - - (752) - - 7,888 293 - - (2,381) - - Total 33,076 7,537 (1,317) 6,862 (1,170) 418 (468) 1,972 46,910 1,278 (5,229) (2,469) 88 (703) 2,575 with these covenants. Unwinding of discount At 31 December 2015 2,575 31,617 5,033 5,800 42,450 In March 2015, the Company reached an agreement to: (i) extend the principal payments that were due in 2015 (amounting to approximately US$ The provision for asset retirement obligation relates to the estimation of future 15,000,000), which will be divided pro-rata during the remaining principal disbursements related to the abandonment and decommissioning of oil and installments, starting in March 2016 and (ii) increase the variable interest rate gas wells (see Note 4). to six-month LI-BOR + 4.0%. (c) During October 2007, GeoPark executed a mortgage loan agreement with economics of the gas wells. The amortisation is in line with the related asset. Banco de Crédito e Inver-siones (BCI), a Chilean private bank, for the acquisition of the operational base in Fell Block. The loan was granted in Chilean pesos Other mainly relates to fiscal controversies associated to income taxes in one and is repayable over a period of 8 years. The interest rate applicable to this of the Colombian subsidiaries. These controversies relate to fiscal periods prior loan is 6.6%. The mortgage loan was fully repaid on October 2015. to the acquisition of these subsidiaries by the Company. In connection to this, Deferred income relates to contributions received to improve the project (d) During December 2015, GeoPark executed a loan agreement with Banco de 5,636,000, with the previous owners for the same amount, which is recognized Chile for US$ 7,028,000 to finance the start-up of new Ache gas field in under other financial assets in the balance sheet. the Company has recorded an account receivable for an amount of US$ GeoPark-operated Fell Block. The interest rate applicable to this loan is LIBOR plus 2.35% per annum. The interest and the principal will be paid on monthly basis; with a six months grace period, with final maturity on December 2017. GeoPark 203 Note 28 Trade and other payables Amounts in US$ ´000 V.A.T Trade payables Payables to related parties(1) (Note 32) Staff costs to be paid Royalties to be paid Taxes and other debts to be paid To be paid to co-venturers Classified as follows: Current Non current On 23 November 2012, the Remuneration Committee and the Board of Directors approved granting 720,000 options over ordinary shares of US$0.001 each to the Executive Directors. Options granted vest on the third anniversary of the date on which they are granted and have an exercise price of US$0.001. On 30 November 2015, the options were exercised and the shares were issued. Additionally, during 2013 the Company approved two new share-based compensation programs: i.) a stock awards plan oriented to Managers (non-Top Management) and key employees who qualifies as an equity-settled 2014 3,449 64,457 16,591 7,226 2,398 10,031 plan and ii.) a cash awards plan, oriented to all non-management employees 1,335 which qualifies as a cash-settled plan. 2015 908 25,906 21,045 6,702 2,475 8,197 113 65,346 105,487 45,790 19,556 88,904 16,583 Main characteristics of these news plans are: • Exercise price: US$ 0.001 • Grant date: July 2013 • Grant price: £ 5.8 (1) The outstanding amount corresponds to a loan granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s blocks. The maturity of this • Vesting date: 31 December 2015 • Conditions to be able to exercise: loan is July 2020 and the applicable interest rate is 8% per annum. - Continue to be an employee The average credit period (expressed as creditor days) during the year ended target for the year of vesting 31 December 2015 was 38 days (2014: 50 days) - The stock market price at the date of vesting should be higher than the share - Obtain the Company minimum Production, Adjusted EBITDA and Reserves The fair value of these short-term financial instruments is not individually • Amount of shares for equity-settled plan: 500,000 determined as the carrying amount is a reasonable approximation of fair value. • Estimated equivalent amount of shares for cash-settled plan: 500,000 price at the price of grant Note 29 Share-based payment Also during 2013, the Company approved a plan named Value Creation Plan (“VCP”) oriented to Top Management. The VCP establishes awards payables in a variable number of shares with some limitation, subject to certain market conditions, among others, reach certain stock market price for the Company IPO Award Program and Executive Stock Option plan share at vesting date. VCP has been classified as an equity-settled plan. The Group has established different stock awards programs and other share-based payment plans to incentivise the Directors, senior management On 10 December 2015, after full discussion by the Compensation Committee and employees, enabling them to benefit from the increased market regarding programs´ conditions, the Committee confirmed conditions will not be capitalization of the Company. achieved (mainly impacted by oil international prices) to execute these programs. Stock Award Program and Other Share Based Payments On 19 December 2014, the Company has approved a new share-based During 2008, GeoPark Shareholders voted to authorize the Board to use up to compensation program for 500,000 shares oriented to new employees. This 12% of the issued share capital of the Company at the relevant time for the new program, which was granted on 31 December 2014, has a vesting period purposes of the Performance-based Employee Long-Term Incentive Plan. of three years. Main characteristics of the Stock Awards Programs are: • All employees are eligible. • Exercise price is equal to the nominal value of shares. • Vesting period is four years. • Specific Award amounts are reviewed and approved by the Executive Directors and the Remuneration Committee of the Board of Directors. 204 GeoPark 20F Awards Awards at Charged to net profit 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: Year of issuance 2014 2013 2012 2011 2010 Subtotal Stock options to Executive Directors 720,000 Shares granted to Non-Executive Directors 23,958 VCP Executive Directors Bonus Key Management Bonus - - - 3,445,558 Awards Awards at the granted in beginning the year 500,000 478,000 428,000 478,000 817,600 - - - - - - 83,882 - 123,839 445,185 652,906 Awards forfeited - 478,000 48,500 - - - - - - - exercised - - - 478,000 817,600 720,000 99,555 - - - year end 500,000 - 379,500 - - - 8,285 - 123,839 445,185 526,500 2,115,155 1,456,809 The awards that are forfeited correspond to employees that had left the Group before vesting date, except for the ones related to the 2013 program that are forfeited because the conditions were not achieved. 2015 898 594 636 879 - 3,007 2014 - 1,291 1,102 848 2,623 5,864 2013 - 619 1,296 893 2,779 5,587 2,390 2,474 2,365 371 617 400 1,438 8,223 223 617 - - 101 309 - - 9,178 8,362 GeoPark 205 Note 30 Interests in Joint operations The Group has interests in nine joint operations, which are engaged in the exploration of hydrocarbons in Chile, Colombia and Brazil. In Chile, GeoPark is the operator in all the blocks. In Colombia, GeoPark is the operator in Llanos 34 and Yamu/Carupana blocks. The following amounts represent the Company’s share in the assets, liabilities and results of the joint operations which have been consolidated line by line in the consolidated statement of financial position and statement of income: 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 GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manati Field PP&E Interest E&E Assets Other Assets Total Assets Current Total Net Assets/ Net Operating Liabilities Liabilities (Liabilities) revenue (loss) profit 50% 50% 50% 60% 36.84% 89,5% 45% 10% - 45 45 14,932 27,570 8,583 - 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) (2,235) (3,295) (213) (2) (53) (10) (16) (93) (2,235) (3,295) (213) 43 - (69) 14,879 27,560 8,567 (93) 3,395 73,801 2,989 1,810 (51,411) 13 355 3 1,409 114,276 8,258 (7,267) (5,661) (6,325) (16,552) 53,049 (1,343) 10% 50,801 12,930 63,731 (10,395) (10,395) 53,336 32,388 20,354 206 GeoPark 20F Subsidiary / Joint operation 2014 GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Llanos 17 Block PP&E Interest E&E Assets Other Assets Total Assets Current Total Net Assets/ Net Operating liabilities Liabilities (Liabilities) revenue (loss) profit 50% 50% 50% 60% 109 35,110 34,309 12,208 36.84% 6,037 - - - - - 109 (125) (125) (16) - (220) 35,110 34,309 12,208 6,037 18,801 78,240 8,936 (1,653) (7,086) (241) (122) (2,727) (3,380) (122) (1,653) (7,086) (241) (122) (2,727) (3,380) (122) 33,457 27,223 11,967 5,915 16,074 74,860 8,814 4,385 216 901 1,292 10,560 176,624 11,024 (6,278) (6,151) (283) (160) (2,916) 96,889 4,041 Yamu/Carupana Block 90% - 79.5% Llanos 34 Block Llanos 32 Block GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. 45% 10% 16,590 76,726 8,909 2,211 1,514 27 Manati Field 10% 46,382 43,891 90,273 (11,587) (11,587) 78,686 35,621 18,935 29% 15,255 210 15,465 (391) (391) 15,074 - (275) 2013 GeoPark Magallanes Ltda. Tranquilo Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Llanos 17 Block 50% 50% 60% 42,048 17,172 4,497 36.84% Yamu/Carupana Block 75% - 54.50% Llanos 34 Block Llanos 32 Block 45% 10% 6,448 15,476 51,963 4,993 Capital commitments are disclosed in Note 31 (b). Note 31 Commitments (a) Royalty commitments - - - 29 482 1,129 - 42,048 17,172 4,497 6,477 15,958 53,092 4,993 (2,537) (405) (303) (2,537) (405) (303) - - - - - - - - 39,511 16,767 4,194 6,477 15,958 53,092 4,993 243 - - 1,407 17,727 78,390 5,507 (239) - - (544) 2,127 39,192 1,035 Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties in connection with Colombian production of light and medium oil are calculated on a field-by-field basis, using the following sliding scale: In Chile, royalties are payable to the Chilean Government. In the Fell Block, Average daily production in barrels Production Royalty rate royalties are calculated at 5% of crude oil production and 3% of gas Up to 5,000 8% production. In the Flamenco Block, Campanario Block and Isla Norte Block, 5,000 to 125,000 8% + (production - 5,000)*0.1 royalties are calculated at 5% of gas and oil production. 125,000 to 400,000 400,000 to 600,000 In Colombia, royalties on production are payable to the Colombian Greater than 600,000 Government and are determined on a field-by-field basis using a level of 20% 20% + (production - 400,000)*0.025 25% production sliding scale at a rate which ranges between 6%-8%. The When the API is lower than 15°, the payment is reduced to the 75% of the total Colombian National Hydrocarbons Agency (“ANH”) also has an additional calculation. economic right equivalent to 1% of production, net of royalties. GeoPark 207 In accordance with Llanos 34 Block operation contract, when the (b) Capital commitments accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and the WTI exceeds the base price settled in Chile table A, the Company should deliver to ANH a share of the production net of On 18 August 2015, the Chilean Ministry accepted the Company’s proposal royalties in accordance with the following formula: Q = ((P – Po) / P) x S; to extend the first exploratory period in the Campanario Block and Isla Norte where Q = Economic right to be delivered to ANH, P = WTI, Po = Base price Block for an additional period of 18 months. The future investment (see table A) and S = Share (see table B). commitments assumed by GeoPark outstanding are up to: Table A °API >29° >22°<29° >15°<22° >10°<15° Table B • Campanario Block: 3 exploratory wells before 11 July 2017 (US$ 11,880,000) Po (US$/barrel) WTI (P) S • Isla Norte Block: 2 exploratory wells before 7 May 2017 (US$ 6,480,000) 30.22 31.39 32.56 46.50 Po < P < 2Po 2Po < P < 3Po 3Po < P < 4Po 4Po < P < 5Po 5Po < P 30% 35% 40% 45% 50% The investments made in the first exploratory period will be assumed 100% by GeoPark. As of 31 December 2015, the Company has established a guarantee for its commitments that amounts to US$ 17,500,000. On 6 January 2016, the Chilean Ministry accepted the Company’s proposal for the commitments related to the second exploratory phase in the Flamenco Block Additionally, under the terms of the Winchester Stock Purchase Agreement, which commenced on 8 November 2015. The investment related to the drilling we are obligated to make certain payments to the previous owners of of one exploratory well will be assumed 100% by GeoPark and shall be made Winchester based on the production and sale of hydrocarbons discovered by before 7 November 2017. The remaining commitment amounts to US$ 2,100,000. exploration wells drilled after October 25, 2011. These payments involve both an earnings based measure and an overriding royalty equal to an Colombia estimated 4% carried interest on the part of the vendor. As at the balance The Llanos 62 Block (100% working interest) has committed to drill two sheet date and based on preliminary internal estimates of additions of 2P exploratory wells before June 2016. The remaining commitment amounts to reserves since acquisition, the Company’s best estimate of the total US$ 6,000,000. commitment over the remaining life of the concession is in a range between US$ 50,000,000 and US$ 60,000,000. During 2015, the Company has accrued The VIM 3 Block minimum investment program consists of 200 sq km of 2D and paid US$ 7,100,000 (US$ 24,600,000 in 2014 and US$ 11,500,000 in 2013) seismic and drilling one exploratory well, with a total estimated investment and US$ 9,200,000 (US$ 21,000,000 in 2014 and US$ 7,800,000 in 2013), of US$ 22,200,000 during the initial three year exploratory period ending in respectively. September 2018. In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency The Llanos 34 Block (45% working interest) has committed to drill two (ANP) is responsible for determining monthly minimum prices for petroleum exploratory wells before September 2017. The remaining commitment produced in concessions for purposes of royalties payable with respect to amounts to US$ 4,320,000 at GeoPark’s working interest. production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and Brazil concession agreement. In determining the percentage of royalties applicable On 14 May 2013, the ANP awarded GeoPark seven new concessions in Brazil to a particular concession, the ANP takes into consideration, among other in an international bidding round, Round 11. For these seven concessions, factors, the geological risks involved and the production levels expected. In GeoPark committed to invest a minimum of US$ 17,000,000 (including the Manatí Block, royalties are calculated at 7.5% of gas production. bonuses and work program commitment for the first exploratory phase). In Argentina, crude oil production accrues royalties payable to the Provinces already invested US$ 6,300,000 in seismic and US$ 4,500,000 in bonuses During this first exploratory phase, that lasts three years, GeoPark has of Santa Cruz and Mendoza equivalent to 12% on estimated value at well paid to ANP. head of those products. This value is equivalent to final sales price less transport, storage and treatment costs. For SEAL-T-268 Block, awarded on 28 November 2013 by the ANP in the international bidding Round 12, GeoPark has committed to invest a minimum of US$ 700,000 (including bonus and work program commitments) during the first exploratory period ending May 2017. 208 GeoPark 20F In October 2015, the Company was awarded four new exploratory blocks in Note 32 the Brazil Bid Round 13. GeoPark has committed to invest for the new blocks, a Related parties minimum of approximately US$ 2,500,000 (including bonus and work program commitments) during the first exploratory period ending December 2018. Controlling interest GeoPark has already invested US$ 370,000 in signature bonus paid to ANP. The main shareholders of GeoPark Limited, a company registered in Bermuda, as of 31 December 2015, are: Argentina On 20 August 2014, the consortium of GeoPark and Pluspetrol was awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as part of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa Mendocina de Energia S.A. (“EMESA”). The consortium consists of Pluspetrol (Operator with a 72% working interest (“WI”), EMESA (Non-operated with a 10% WI) and GeoPark (Non-operated with an 18% WI). GeoPark has committed to a minimum aggregate investment of US$ 6,200,000 for its WI, which includes the work program commitment on both blocks during the first three years of the exploratory period. On 22 July 2015, the Company signed a farm-in agreement with Wintershall for the CN-V Block in Argentina. GeoPark will operate during the exploratory phase and receive a 50% working interest in the CN-V Block in exchange for its commitment to drill two exploratory wells, for a total of US$ 10,000,000. Shareholder Cartica Management LLC(1) Gerald E. O’Shaughnessy(2) James F. Park(3) IFC Equity Investments(4) Moneda A.F.I.(5) Juan Cristóbal Pavez(6) Other shareholders Percentage of outstanding Common common shares 9,690,972 7,871,276 7,891,269 3,456,594 3,184,650 2,913,709 shares 16.28% 13.22% 13.25% 5.81% 5.35% 4.89% 24,527,144 59,535,614 41.20% 100.00% (1) Held through certain private investment funds managed and controlled by Cartica Management, LLC. Mr. Steven Quamme and Mrs. Farida Khambata, partners at Cartica Management LLC, are deemed to have shared voting and (c) Operating lease commitments – Group company as lessee investment power over such shares, added to the shares personally held by The Group leases various plant and machinery under non-cancellable each one of them. Mr. Quamme personally holds 20,236 shares and therefore operating lease agreements. The Group also leases offices under non-cancellable operating lease agreements. The lease terms are between 2 and 3 years, and the majority of lease agreements are renewable at the end of the lease period at market rate. During 2015 a total amount of US$ 16,731,000 (US$ 19,409,000 in 2014 and US$19,110,000 in 2013) was charged to the income statement and US$ is deemed to beneficially own an aggregate of 9,711,208 shares and Mrs. Farida Khambata personally holds 75,151 shares and therefore is deemed to beneficially own an aggregate of 9,766,123 shares. (2) Beneficially owned by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP, The Globe Resources Group Inc., and other investment vehicles. (3) 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 7,102,000 of operating leases were capitalised as Property, plant and Mr. Park does not reflect the 328,812 common shares held as of 31 December equipment (US$ 51,341,000 in 2014 and US$ 37,263,000 in 2013). 2015 in the employee benefit trust described under ‘‘Management— The future aggregate minimum lease payments under non-cancellable operating leases are as follows: Amounts in US$ ´000 2015 2014 2013 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 12,878 8,257 2,456 309 37,926 33,949 16,109 505 68,817 56,556 31,145 505 Total minimum lease payments 23,900 88,489 157,023 Compensation—Employee Benefit Trust’’. (4) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff. (5) Held through various funds managed by Moneda A.F.I. (Administradora de Fondos de Inversión), an asset manager. (6) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 35,905 common shares held by him personally. GeoPark 209 Balances outstanding and transactions with related parties Amounts in US$ ´000 2015 To be recovered from co-venturers Prepayments and other receivables Payables account To be paid to co-venturers Financial costs Geological and geophysical expenses Administrative expenses Administrative expenses 2014 To be recovered from co-venturers Payables account To be paid to co-venturers Financial costs Geological and geophysical expenses Administrative expenses Administrative expenses 2013 To be recovered from co-venturers Payables account To be paid to co-venturers Financial costs Geological and geophysical expenses Administrative expenses Transaction in the year Balances at year end Related Party Relationship - - - - 1,560 101 66 377 - - - 592 16 114 568 - - - 112 24 176 4,634 38 (21,045) (113) - - - - 5,931 (16,591) (1,335) - - - - 15,508 (8,456) (1,201) - - - Joint Operations Joint Operations LGI LGI Partner Partner Joint Operations Joint Operations LGI Carlos Gulisano Carlos Gulisano Pedro Aylwin Partner Non-Executive Director (*) Non-Executive Director (*) Executive Director(**) Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations LGI Carlos Gulisano Carlos Gulisano Pedro Aylwin Partner Non-Executive Director(*) Non-Executive Director(*) Executive Director(**) Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations LGI Carlos Gulisano Carlos Gulisano Partner Non-Executive Director(*) Non-Executive Director(*) (*) Corresponding to consultancy services. (**) Corresponding to wages and salaries for US$ 317,000 (US$ 374,000 in 2014) and bonus for US$ 60,000 (US$ 194,000 in 2014). There have been no other transactions with the Board of Directors, Executive Board, 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 Executive Board and other benefits informed in Note 10. 210 GeoPark 20F Note 33 Fees paid to Auditors Amounts in US$ ´000 Audit fees Tax services fees Non-audit services fees Fees paid to auditors (*) Include fees related to the IPO process. b. Brazil Acquisition in Brazil 2015 557 129 - 686 2014 620 281 540 2013 1,091(*) 292 GeoPark entered into Brazil with the acquisition of a 10% working interest in the offshore Manati gas field (“Manati Field”), the largest natural gas producing field in Brazil. On 14 May, 2013, GeoPark executed a stock purchase agreement 45 (“SPA”) with Panoro Energy do Brazil Ltda., the subsidiary of Panoro Energy 1,441 1,428 ASA, (“Panoro”), a Norwegian listed company with assets in Brazil and Africa, to acquire all of the issued and outstanding shares of its wholly-owned Brazilian subsidiary, Rio das Contas Produtora de Petróleo Ltda (“Rio das Contas”), the direct owner of 10% of the BCAM-40 Block (the “Block”), which includes the Non-audit services fees relates to due diligence, consultancy and other shallow-depth offshore Manati Field in the Camamu-Almada basin. services for 2014 and 2013. Note 34 Business transactions a. Colombia Swap operation GeoPark has paid a cash consideration of US$ 140 million at 31 March 2014 or the closing date, which was adjusted for working capital with an effective date of 30 April 2013. The agreement also provides for possible future contingent payments by GeoPark over the next five years, depending on the economic performance and cash generation of the Block. The Company has estimated that there are no any future contingent payments at the acquisition date and as of the date of these financial statements either. On 19 November 2015, GeoPark’s Colombian subsidiary agreed to exchange The Manati Field is a strategically important, profitable upstream asset in Brazil its 10% non-operating economic interest in Cerrito Block for additional and currently provides approximately 50% of the gas supplied to the interests held by Trayectoria, the counterpart in the Yamú Block, operated by northeastern region of Brazil and more than 75% of the gas supplied to GeoPark, that includes a 10% economic interest in all of the Yamú fields. Salvador, the largest city and capital of the northeastern state of Bahia. The According to the terms of the swap operation, GeoPark written off a receivable field is largely developed with existing producing wells and an extensive with Trayectoria. Following this transaction, GeoPark shall continue to be the pipeline, treatment and delivery infrastructure and is not expected to require operator and have an 89.5% interest in the Carupana Field and 100% in Yamú significant future capital expenditures to meet current production estimates. and Potrillo Fields, all fields located in the Yamú Block. The Company recognized a US$ 296,000 loss as a result of this transaction. The Manati Field is operated by Petrobras (35% working interest), the Brazilian national company, largest oil and gas operator in Brazil and internationally- On 29 July 2014, GeoPark’s Colombian subsidiary agreed to exchange its 10% respected offshore operator. Other partners in the Block include Queiroz non-operating economic interest in Arrendajo Block for additional interests Galvao Exploração e Produção (45% working interest) and Brasoil Manati held by the counterpart in the Yamú Block (GeoPark operated) that includes a Exploração Petrolífera S.A. (10% working interest). 15% economic interest in all of the Yamú fields except for the Carupana field, where the counterparty had a 25% economic interest. According to the terms In accordance with the acquisition method of accounting, the acquisition cost of the exchange, GeoPark received US$ 3,200,000 in cash from the exchange, was allocated to the underlying assets acquired and liabilities assumed based adjusted by working capital. Following this transaction, GeoPark shall continue primarily upon their estimated fair values at the date of acquisition. An income to be the operator and have a 79.5% interest in the Carupana Field and 90% in approach (being the net present value of expected future cash flows) was Yamú and Potrillo Fields, all fields located in the Yamú Block. This transaction adopted to determine the fair values of the mineral interest. Estimates of had no impact on the results of the Company. expected future cash flows reflect estimates of projected future revenues, production costs and capital expenditures based on our business model. GeoPark 211 The following table summarises the consideration paid, the fair value of assets Round 13 acquired and liabilities assumed for the abovementioned transaction: In October 2015, the Company was awarded four new exploratory blocks Amounts in US$ ´000 (covering 30,200 acres) in the Brazil Bid Round 13, complementing the Total Company’s existing exploration portfolio in the Reconcavo and Potiguar Cash (including working capital adjustments) 140,100 basins. The bidding round was organized by the ANP and all proceedings and Total consideration Cash and cash equivalents 140,100 bids have been made public. The winning bids are subject to confirmation of 25,133 qualification requirements. Property, plant and equipment (including mineral interest) 112,847 Trade receivables Prepayments and other receivables Other financial assets Deferred income tax liabilities Trade and other payables Provision for other long-term liabilities Total identifiable net assets 9,757 5,945 950 (3,132) (4,538) (6,862) The awarded blocks were: Block (Basin) POT-T-747 (Potiguar) POT-T-882 (Potiguar) 140,100 REC-T-93 (Reconcavo) REC-T-128 (Reconcavo) Working Interest (WI) Operator 70% (*) 70% (*) 70% 70% GeoPark GeoPark GeoPark GeoPark The purchase price allocation above mentioned is final. Acquisition-related costs have been charged to administrative expenses in the consolidated (*) 30% WI of proposed partners is subject to ANP approval. income statement for the year ended 31 December 2012. The revenue included in the consolidated statement of comprehensive income since acquisition date contributed by the acquired company was Entry in Peru c. Peru US$ 35,621,000 for the year 2014. The acquired company also contributed The Company has executed a Joint Investment Agreement and Joint profit of US$ 18,952,000 over the same period. Had Rio das Contas been Operating Agreement with Petróleos del Peru S.A. (“Petroperu”) to acquire an consolidated from 1 January 2014 the consolidated statement of income interest in and operate the Morona Block located in northern Peru. GeoPark would show pro-forma revenue of US$ 440,298,000 and profit of US$ will assume a 75% working interest (“WI”) of the Morona Block, with Petroperu 23,139,000 for the year 2014. retaining a 25% WI. The transaction has been approved by the Board of Directors of both Petroperu and GeoPark. Round 12 On 28 November 2013, the ANP awarded GeoPark two concessions in the The transaction is subject to customary conditions, certain license ANP´s 12th Bid Round. One of these two concessions was the Block PN-T-597. modifications and a presidential decree. As a result of a class action filed by the Federal Prosecutor’s Office, an injunction was issued by a Brazilian Federal Court against the ANP, the Federal The Morona Block, also known as Lote 64, covers an area of 1.9 million acres on Government and GeoPark Brazil on 13 December 2013. Due to the injunction the western side of the Marañón Basin, one of the most prolific hydrocarbon to which GeoPark Brazil had interpreted that it could not proceed to execution basins in Peru. of the concession agreement, GeoPark filed a request to the ANP to suspend the execution of the Concession Agreement. In April 2015, GeoPark was called The Morona Block contains the Situche Central oil field, which has been to have the contract signed, which occurred on 17 July 2015. Notwithstanding delineated by two wells (with short term tests of approximately 2,400 and all GeoPark efforts to seek for clarification to whether or not the Concession 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the Situche Agreement could be executed according to ANP´s understanding, the judge Central field, the Morona Block has a large exploration potential with several issued an interlocutory decision on 13 August 2015, with a clear position that high impact prospects and plays – with exploration resources currently the Concession Agreement should not be executed. GeoPark immediately filed estimated to range from 200 to 600 mmbo. a Request towards ANP to annul the signature of the contract and all its effects and revert to the status quo ante, which maintains Geopark´s right to the The Morona Block includes geophysical surveys of 2,783 km (2D seismic) and Block. On 9 October 2015, ANP´s Board issued the Resolution 828/2015 which 465 sq km (3D seismic), and an operating field camp and logistics approved the annulment of the signature of the Contract and revoked the infrastructure. The expected work program and development plan for the previous Decision that called GeoPark for the signature. Situche Central oil field is to be completed in three stages. 212 GeoPark 20F The goal of the initial stage will be to put the field into production through a In addition, actions taken by the Company to maximize ongoing work projects long term test to help determine the most effective overall development plan and to reduce expenses, including renegotiations and reduction of oil and gas and to begin to generate cash flow. This initial stage requires an investment of service contracts and other initiatives included in the cost cutting program approximately US$ 140,000,000 to US$ 160,000,000 and is expected to be adopted may expose the Company to claims and contingencies from completed within 18 to 24 months after closing. GeoPark has committed to carry interested parties that may have a negative impact on its business, financial Petroperu during this initial phase. The subsequent work program stages, which condition, results of operations and cash flows. As of the date of these will be initiated once production has been established, are focused on carrying consolidated financial statements, according to internal estimates, the out the full development of the Situche Central field, including transportation Company has recognized approximately US$ 4,100,000 for future contingent infrastructure, and new exploration drilling of the block. Petroperu will also have payments in connection with claims of third parties. The mentioned costs are the right to increase its WI in the block up to 50%, subject to GeoPark recovering allocated under the other (expenses) income line, included in the Consolidated its investments in the block by certain agreed factors. Statement of Income. GeoPark has already been qualified as an Operator by Perupetro, the Peruvian petroleum licensing agency. As of the date of the issuance of these Note 36 Consolidated Financial Statements, the transaction is pending of approval. Impairment test on Property, plant and equipment Note 35 As a result of the situation described in Note 35, the Company evaluated the recoverability of its fixed assets affected by oil price drop, as such situation Oil industry situation and the impact on GeoPark’s operations constitutes an impairment indicator according to IAS 36 and, consequently, it triggers the need of assessing fair value of the assets involved against their Oil price crisis started in the second half of 2014 and prices fell dramatically, WTI carrying amount. and Brent, the main international oil price markers, fell more than 60% between October 2014 and February 2016. During 2015, prices have remained low and The Management of the Company considers as Cash Generating Unit (CGU) volatile (WTI and Brent fell more than 40% between March 2015 and February each of the blocks in which the Group has working or economic interests. The 2016). As a consequence of this market conditions, the Company has undertaken blocks with no material investment on fixed assets or with operations that are a decisive cost cutting program to ensure its ability to both maximize the work not linked to oil prices were not subject to impairment test. program and preserve its liquidity. The main decisions included: The main assumptions taken into account for the impairment tests for the • Reduction of its capital investment taking advantage of the discretionary blocks below mentioned were: work program. • Deferment of capital projects by regulatory authority and partner agreement. • The future oil prices have been calculated taking into consideration the oil • Renegotiation and reduction of oil and gas service contracts, including curves prices available in the market, provided by international advisory drilling and civil work contractors, as well as transportation trucking and companies, weighted through internal estimations in accordance with price pipeline costs. curves used by D&M; • Operating cost improved efficiencies and temporary suspension of certain • Three price scenarios were projected and weighted in order to minimize marginal producing oil and gas fields. misleading: low price, middle price and high price (see below table “Oil price • Further cost reductions are expected to result from a general depreciation of scenarios”); Latin American currencies (Colombian peso, Brazilian real, Chilean peso, • The table “Oil price scenarios” was based on WTI future price estimations; the Argentine peso and Peruvian sol), in connection with operating and structure Company adjusted this marker price on its model valuation to reflect the costs established in local currencies. effective price applicable in each location (see Note 3 “Price risk”); • The model valuation was based on the expected cash flow approach; During February 2015, the Company reduced its workforce significantly. This • The revenues were calculated linking price curves with levels of production reduction streamlined certain internal functions and departments for creating according to certified reserves (see below table “Oil price scenarios”); a more efficient workforce in the current economic environment. As a result, • The levels of production have been linked to certified risked 1P, 2P and 3P the Company achieved cost savings associated with the reduction of full-time reserves (see Note 4); and temporary employees, excluding one-time termination costs. Continuous • Production and structure costs were estimated considering internal efforts and actions to reduce costs and preserve liquidity have continued historical data according to GeoPark’s own records and aligned to 2016 throughout the year and will continue in the future. approved budget; GeoPark 213 • The capital expenditures were estimated considering the drilling campaign necessary to develop the certified reserves; • The assets subject to impairment test are the ones classified as Oil and Gas properties and Production facilities and machinery; • The carrying amount subject to impairment test includes mineral interest, if any; • The income tax charges have considered future changes in the applicable income tax rates (see Note 15). Table Oil price scenarios(*): Year 2016 2017 2018 2019 2020 Over 2021 Amounts in US$ per Bbl. Weighted market price used for Low price (15%) Middle price (60%) High price (25%) the impairment test 35,7 39,0 49,4 53,1 56,7 59,6 35,7 46,8 59,3 63,7 68,1 71,5 39,3 57,2 72,5 77,8 83,2 87,4 36,6 48,3 61,1 65,6 70,2 73,7 (*) The percentages indicated between brackets represent the Company estimation regarding each price scenario. Summary for impairment: Country Chile Brazil Colombia Carrying Impairment amount loss Pre-tax (US$ million) (US$ million) discount rate 354,3 50,8 101,5 104,5 - 45,1 12.8% 16.2% 17.1% If the weighted market price used for the impairment test had been 5% lower in each of the future years, with all other variables held constant, the impairment loss would have been higher by approximately US$ 29,000,000. Peru and Argentina segments have no associated assets subject to impairment. 214 GeoPark 20F Note 37 Supplemental information on oil and gas activities (unaudited) Table 1 - Costs incurred in exploration, property acquisitions and development(1) The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended as of 31 December 2015, 2014 The following information is presented in accordance with ASC No. 932 and 2013. The acquisition of properties includes the cost of acquisition of “Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas proved or unproved oil and gas properties. Exploration costs include Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order geological and geophysical costs, costs necessary for retaining undeveloped to align the current estimation and disclosure requirements with the properties, drilling costs and exploratory well equipment. Development costs requirements set in the SEC final rules and interpretations, published on include drilling costs and equipment for developmental wells, the construction December 31, 2008. This information includes the Company’s oil and gas of facilities for extraction, treatment and storage of hydrocarbons and all production activities carried out in Chile, Colombia, Brazil and Argentina. necessary costs to maintain facilities for the existing developed reserves. Amounts in US$ ´000 Year ended 31 December 2015 Acquisition of properties - Proved - Unproved Total property acquisition Exploration Development Total costs incurred Amounts in US$ ´000 Year ended 31 December 2014 Acquisition of properties - Proved - Unproved Total property acquisition Exploration Development Total costs incurred Amounts in US$ ´000 Year ended 31 December 2013 Acquisition of properties - Proved - Unproved Total property acquisition Exploration Development Total costs incurred (1) Includes capitalised amounts related to asset retirement obligations. Chile Colombia Argentina Brazil 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 Chile Colombia Argentina Brazil Total - - - 84,251 82,742 166,993 - - - 14,114 55,336 69,450 - - - (123) 126 3 112,646 112,646 - 112,646 12,004 1,052 125,702 - 112,646 110,246 139,256 362,148 Chile Colombia Argentina Brazil Total - - - 91,140 61,748 152,888 - - - 47,668 37,983 85,651 - - - (1,917) 124 (1,793) - - - 1,702 - 1,702 - - - 138,593 99,855 238,448 GeoPark 215 Table 2 - Capitalised costs related to oil and gas producing activities The following table presents the capitalized costs as at 31 December 2015, 2014 and 2013, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates. Amounts in US$ ´000 At 31 December 2015 Proved properties - Equipment, camps and other facilities(1) - Mineral interest and wells(1) - Other uncompleted projects(1) Unproved properties Gross capitalised costs Accumulated depreciation Total net capitalised costs Chile Colombia Argentina Brazil Total 79,040 367,722 21,830 70,062 538,654 (201,138) 337,516 42,852 213,480 7,703 8,180 272,215 (160,759) 111,456 843 4,849 290 - 5,982 (5,654) 328 2,097 62,941 - 8,758 73,796 (14,236) 59,560 124,832 648,992 29,823 87,000 890,647 (381,787) 508,860 (1) 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. Amounts in US$ ´000 At 31 December 2014 Proved properties - Equipment, camps and other facilities - Mineral interest and wells(1) - Other uncompleted projects Unproved properties Gross capitalised costs Accumulated depreciation Total net capitalised costs Chile Colombia Argentina Brazil Total 81,998 426,638 37,902 113,403 659,941 (163,217) 496,724 28,805 227,755 20,204 18,176 294,940 (111,855) 183,085 843 4,849 - - 5,692 (5,562) 130 - 90,705 1,053 8,865 111,646 749,947 59,159 140,444 100,623 1,061,196 (4,951) 95,672 (285,585) 775,611 (1) Includes capitalised amounts related to asset retirement obligations and impairment loss in Colombia for US$ 9,430,000. Amounts in US$ ´000 At 31 December 2013 Proved properties - Equipment, camps and other facilities - Mineral interest and wells(1) - Other uncompleted projects Unproved properties Gross capitalised costs Accumulated depreciation Total net capitalised costs Chile Colombia Argentina Brazil Total 77,481 310,364 33,176 109,862 530,883 (127,447) 403,436 20,514 178,048 7,053 37,853 243,468 (60,150) 183,318 843 4,849 - 31 5,723 (5,470) 253 - - - 13 13 - 13 98,838 493,261 40,229 147,759 780,087 (193,067) 587,020 (1) Includes capitalised amounts related to asset retirement obligations. 216 GeoPark 20F 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 2015, 2014 and 2013. Income tax for the years presented was calculated utilizing the statutory tax rates. Amounts in US$ ´000 Year ended 31 December 2015 Net revenue Production costs, excluding depreciation - Operating costs - Royalties Total production costs Exploration expenses(1) Accretion expense(2) 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 Amounts in US$ ´000 Year ended 31 December 2014 Net revenue Production costs, excluding depreciation - Operating costs - Royalties Total production costs Exploration expenses(1) Accretion expense(2) 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 (1) Do not include Peru costs. (2) Represents accretion of ARO liability. Chile Colombia Argentina Brazil Total 44,808 131,897 597 32,388 209,690 (26,731) (1,973) (28,704) (30,499) (789) (104,515) (37,664) (157,363) 23,604 (133,759) (40,384) (8,150) (48,534) (7,132) (890) (45,059) (50,675) (20,393) 7,953 (12,440) (1,414) (34) (1,448) (1,159) - - (91) (2,101) 735 (1,366) (5,058) (2,998) (8,056) (1,103) (896) - (13,401) 8,932 (3,037) 5,895 (73,587) (13,155) (86,742) (39,893) (2,575) (149,574) (101,831) (170,925) 29,255 (141,670) Chile Colombia Argentina Brazil Total 145,720 246,085 (34,991) (6,777) (41,768) (36,057) (816) - (35,856) 31,223 (4,684) 26,539 (67,470) (12,354) (79,824) (4,567) (547) (9,430) (51,856) 99,861 (33,953) 65,908 1,308 (309) (241) (550) 123 - - (94) 787 (275) 512 35,621 428,734 (5,354) (2,794) (8,148) (2,164) (609) - (11,554) 13,146 (4,470) 8,676 (108,124) (22,166) (130,290) (42,665) (1,972) (9,430) (99,360) 145,017 (43,382) 101,635 GeoPark 217 Amounts in US$ ´000 Year ended 31 December 2013 Net revenue Production costs, excluding depreciation - Operating costs - Royalties Total production costs Exploration expenses Accretion expense(2) Depreciation, depletion and amortization Results of operations before income tax Income tax (expense) benefit Results of oil and gas operations (2) Represents accretion of ARO liability. Chile Colombia Argentina Brazil Total 157,491 179,324 (30,915) (7,383) (38,298) (13,138) (429) (29,287) 76,339 (11,451) 64,888 (62,818) (9,661) (72,479) (3,341) (880) (39,233) 63,391 (20,919) 42,472 1,538 (92) (195) (287) 1,928 (214) (59) 2,906 (1,017) 1,889 - - - - (1,703) - - (1,703) 579 (1,124) 338,353 (93,825) (17,239) (111,064) (16,254) (1,523) (68,579) 140,933 (32,808) 108,125 Table 4 - Reserve quantity information The Company estimates its reserves at least once a year. The Company’s Estimated oil and gas reserves reserves estimation as of 31 December 2015, 2014 and 2013 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). Proved reserves represent estimated quantities of oil (including crude oil and DeGolyer and MacNaughton prepared its proved oil and natural gas reserve condensate) and natural gas, which available geological and engineering data estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by the demonstrates with reasonable certainty to be recoverable in the future from SEC, and in accordance with the oil and gas reserves disclosure provisions of known reservoirs under existing economic and operating conditions. Proved ASC 932 of the FASB Accounting Standards Codification (ASC) relating to developed reserves are proved reserves that can reasonably be expected to be Extractive Activities—Oil and Gas (formerly SFAS no. 69 Disclosures about Oil recovered through existing wells with existing equipment and operating and Gas Producing Activities). methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, Reserves engineering is a subjective process of estimation of hydrocarbon quality and reliability of basic data, and production history. accumulation, which cannot be accurately measured, and the reserve estimation The Company believes that its estimates of remaining proved recoverable oil judgment of the engineers and geologists. Therefore, the reserves estimations, and gas reserve volumes are reasonable and such estimates have been as well as future production profiles, are often different than the quantities of prepared in accordance with the SEC Modernization of Oil and Gas Reporting hydrocarbons which are finally recovered. The accuracy of such estimations rules, which were issued by the SEC at the end of 2008. depends, in general, on the assumptions on which they are based. depends on the quality of available information and the interpretation and The estimated GeoPark net proved reserves for the properties evaluated as of 31 December 2015, 2014 and 2013 are summarised as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf ): 218 GeoPark 20F Net proved developed Chile(1) Colombia(2) Brazil(3) Total consolidated Net proved undeveloped Chile(4) Colombia(5) Brazil(3) Total consolidated Total proved reserves As of 31 December 2015 As of 31 December 2014 As of 31 December 2013 Oil and Oil and Oil and condensate Natural gas condensate Natural gas condensate Natural gas (Mbbl) (MMcf ) (Mbbl) (MMcf ) (Mbbl) (MMcf ) 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 - 36,158.0 41,080.0 31,593.0 - - 31,593.0 72,673.0 1,463.7 7,594.8 69.0 9,127.5 4,978.2 17,140.5 61.0 22,179.7 31,307.2 9,352.0 - 20,863.0 30,215.0 24,618.0 - 19,601.0 44,219.0 74,434.0 2,236.6 3,250.9 - 5,487.5 3,138.4 6,175.7 - 9,314.1 14,801.6 10,037.0 - - 10,037.0 22,122.0 - - 22,122.0 32,159.0 (1) Fell Block accounts for 91% of the reserves (92% in 2014 and 100% in 2013) (LGI owns a 20% interest) and Flamenco Block accounts for 9% (8% in 2014) (LGI owns 31.2% interest). (2) Llanos 34 Block and Cuerva Block account for 94% and 3% (79% and 17% in 2014 and 58% and 36% in 2013) of the proved developed reserves, respectively (LGI owns a 20% interest). (3) BCAM-40 Block accounts for 100% of the reserves. (4) Fell Block accounts for 100% of the reserves (96% in 2014 and 100% in 2013) (LGI owns a 20% interest), (Flamenco Block accounts for 3% and Isla Norte accounts for 1% 2014) (LGI owns 31.2% interest). (5) Llanos 34 Block and Cuerva Block account for 95% and 4% (91% and 7% in 2014 and 74% and 23% in 2013) of the proved undeveloped reserves, respectively (LGI owns a 20% interest). GeoPark 219 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 2012 Increase (decrease) attributable to: - Revisions - Extensions and discoveries(1) - Production Reserves as of 31 December 2013 Increase (decrease) attributable to: - Revisions(2) - Extensions and discoveries(3) - Purchases of minerals in place - Production Reserves as of 31 December 2014 Increase (decrease) attributable to: - Revisions - Extensions and discoveries(4) - Production Reserves as of 31 December 2015 (1) Mainly due to 2013 discoveries in Llanos 34 (Taro Taro, Tigana and Tigana Sur) and Yamú (Potrillo). (2) In Chile, the revisions are mainly due to Field’s performance in Fell and TdF Blocks. In Colombia, the revisions are mainly due to the performance of Tua Field and secondly to the performance of Max and Taro-taro Fields in Llanos 34 Block. (3) In Chile, the discoveries mainly due to Loij Field discovery and Konawentru Field extensions. In Colombia, the discoveries mainly due to Tigana Field extensions wells and Aruco Field discovery in Llanos 34 Block. (4) In Colombia, the extensions and discoveries are primarily due to the Tilo, Jacana, and Chachalaca field discoveries in the Llanos 34 Block. Chile 5,258.1 271.1 1,431.0 (1,585.2) 5,375.0 124.9 2,314.0 - (1,372.0) 6,441.9 119.0 100.0 (707.1) 5,953.8 Colombia 6,627.0 (277.0) 5,210.0 (2,133.4) 9,426.6 2,489.7 16,477.0 - (3,658.0) 24,735.3 (1.0) 10,489.0 (4,800.0) 30,423.3 Brazil - - - - - - - 150.0 (20.0) 130.0 7.6 - (17.6) 120.0 Total 11,885.1 (5.9) 6,641.0 (3,718.6) 14,801.6 2,614.6 18,791.0 150.0 (5,050.0) 31,307.2 125.6 10,589.0 (5,524.7) 36,497.1 220 GeoPark 20F Net proved reserves (developed and undeveloped) of natural gas: Millions of cubic feet Reserves as of 31 December 2012 Increase (decrease) attributable to: - Revisions(1) - Extensions and discoveries - Production Reserves as of 31 December 2013 Increase (decrease) attributable to: - Revisions(2) - Extensions and discoveries(3) - Purchases of minerals in place - Production Reserves as of 31 December 2014 Increase (decrease) attributable to: - Revisions(4) - Extensions and discoveries(5) - Production Reserves as of 31 December 2015 (1) The revisions are mainly due to adjustments in the Fell Block as a response to a workover in Monte Aymond field, and associated gas from drilling campaigns in Konawentru and Yagán Norte fields. (2) The revisions are mainly due to Chercán Field development in TdF Block and gas and associated gas performance/development in Fields of Fell Block. (3) Mainly due to the Ache Field discovery and the associated gas from Konawentru extension well. (4) In Brazil, the revisions are primary due to the production performance of Manati field. (5) In Chile, the extensions and discoveries are primary due to the Ache Field discovery and from the extension well in the Fell Block. Revisions refer to changes in interpretation of discovered accumulations and some technical / logistical needs in the area obliged to modify the timing and development plan of certain fields under appraisal and development phases. Chile 29,581.0 4,691.0 2,219.0 (4,332.0) 32,159.0 3,312.0 3,014.0 - (4,515.0) 33,970.0 (2,680.0) 9,378.0 (4,153.0) 36,515.0 Brazil - - - - - - - 47,680.0 (7,216.0) 40,464.0 2,907.0 - (7,213.0) 36,158.0 Total 29,581.0 4,691.0 2,219.0 (4,332.0) 32,159.0 3,312.0 3,014.0 47,680.0 (11,731.0) 74,434.0 227.0 9,378.0 (11,366.0) 72,673.0 GeoPark 221 Table 6 - Standardized measure of discounted future net cash flows related to This standardized measure is not intended to be and should not be proved oil and gas reserves interpreted as an estimate of the market value of the Company’s reserves. The purpose of this information is to give standardized data to help the users of The following table discloses estimated future net cash flows from future the financial statements to compare different companies and make certain production of proved developed and undeveloped reserves of crude oil, projections. It is important to point out that this information does not include, condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas among other items, the effect of future changes in prices, costs and tax rates, Reporting rules and ASC 932 of the FASB Accounting Standards Codification which past experience indicates that are likely to occur, as well as the effect of (ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 future cash flows from reserves which have not yet been classified as proved Disclosures about Oil and Gas Producing Activities), such future net cash flows reserves, of a discount factor more representative of the value of money over were estimated using the average first day- of-the-month price during the the lapse of time and of the risks inherent to the production of oil and gas. 12-month period for 2015, 2014 and 2013 and using a 10% annual discount These future changes may have a significant impact on the future net cash factor. Future development and abandonment costs include estimated drilling flows disclosed below. For all these reasons, this information does not costs, development and exploitation installations and abandonment costs. necessarily indicate the perception the Company has on the discounted future These future development costs were estimated based on evaluations made by net cash flows derived from the reserves of hydrocarbons. the Company. The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which we have interests, as of the date this supplementary information was filed. Amounts in US$ ‘000 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 At 31 December 2014 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 2013 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 222 GeoPark 20F Chile Colombia Brazil Total 403,199 (186,933) (112,312) (17,904) 86,050 (17,895) 68,155 778,820 (250,529) (184,352) (54,442) 289,497 (61,839) 227,658 610,106 (164,820) (215,426) (38,599) 191,261 (27,401) 163,860 1,032,339 (309,394) (99,305) (195,957) 427,683 (127,586) 300,097 1,732,395 (587,096) (100,036) (303,090) 742,173 (158,102) 584,071 686,227 (274,246) (82,964) (118,104) 210,913 (37,121) 173,792 221,206 (99,832) (16,360) (16,837) 88,177 (15,861) 72,316 307,535 (124,265) (19,965) (19,566) 143,739 (31,594) 112,145 - - - - - - - 1,656,744 (596,159) (227,977) (230,698) 601,910 (161,342) 440,568 2,818,750 (961,890) (304,353) (377,098) 1,175,409 (251,535) 923,874 1,296,333 (439,066) (298,390) (156,703) 402,174 (64,522) 337,652 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 2012 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 2013 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 Purchase of minerals in place Accretion of discount 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 Chile 202,449 (128,993) (4,925) (118,760) 63,948 83,983 37,389 4,102 24,667 163,860 (110,451) 18,310 (134,272) 96,614 157,988 25,114 (9,751) - 20,246 227,658 (20,948) (256,828) 28,227 23,595 15,093 (5,463) 28,611 28,210 68,155 Colombia 133,645 (118,417) 4,754 (68,337) 186,738 39,922 (9,928) (17,827) 23,242 173,792 (208,337) 19,215 (51,176) 600,391 59,272 103,411 (141,687) - 29,190 584,071 (97,152) (547,379) (20,123) 174,951 29,965 (14,528) 101,576 88,716 300,097 Brazil - - - - - - - - - - (39,414) 7,409 (22,143) - 1,340 1,559 4,156 142,423 16,815 112,145 (37,428) (27,404) 542 - 4,872 4,845 1,573 13,171 72,316 Total 336,094 (247,410) (171) (187,097) 250,686 123,905 27,461 (13,725) 47,909 337,652 (358,202) 44,934 (207,591) 697,005 218,600 130,084 (147,282) 142,423 66,251 923,874 (155,528) (831,611) 8,646 198,546 49,930 (15,146) 131,760 130,097 440,568 GeoPark 223 224 Annual Report 2015 GeoPark 225 226 Annual Report 2015 GeoPark 227 Peter Ryalls | Non-Executive Director Mr. Ryalls has been a member of our board of directors since April 2006. Mr. Ryalls started his career working as a wireline engineer for schlumberger in West Africa. Returning to the UK in 1976 to study for his Master’s degree in Petroleum engineering at imperial college London following which he joined Mobil North sea. He moved to Unocal corporation in 1979 where he held increasingly senior positions, including as Managing director of Unocal UK in Aberdeen, scotland, and where he developed extensive experience in offshore production and drilling operations. in 1994, Mr. Ryalls represented Unocal corporation in the Azerbaijan international operating company as Vice President of operations and was responsible for production, drilling, reservoir engineering and logistics. in 1998, Mr. Ryalls became General Manager for Unocal in Argentina. He also served as Vice President of Unocal’s Gulf of Mexico onshore oil and gas business and as Vice President of Global engineering and construction, where he was responsible for the implementation of all major capital projects ranging from deep water developments in indonesia and the Gulf of Mexico to conventional oil and gas projects in thailand. Mr. Ryalls is also an independent Petroleum consultant advising on international oil and gas development projects both onshore and offshore. Bob Bedingfield | Non-Executive Director Mr. Bedignfield has been a member of our board of directors since March 2015. He holds a degree in Accounting from the University of Maryland and is a certified Public Accountant. Until his retirement in June 2013, he was one of ernst & Young’s most senior Global Lead Partners with more than 40 years of experience, including 32 years as a partner in ernst & Young’s accounting and auditing practices, as well as serving on ernst & Young’s senior Governing Board. He has extensive experience serving fortune 500 companies; including acting as Lead Audit Partner or senior Advisory Partner for Lockheed Martin, Aes, Gannett, General dynamics, Booz Allen Hamilton, Marriott and the Us Postal service. since 2000, Mr. Bedingfield has been a trustee, and at times an executive committee Member, and the Audit committee chair of the University of Maryland at college Park Board of trustees. Mr. Bedingfield served on the National executive Board (1995 to 2003) and National Advisory council (since 2003) of the Boy scouts of America. since 2013, Mr. Bedingfield has also served as Board Member and chairman of the Audit committee of NYse-listed science Applications international corp (sAic). 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. 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 and tectonic research at the University of texas. in 1978, Mr. Park joined Basic Resources international Limited, an oil and gas exploration company, which pioneered the development of commercial oil and gas production in central America. As a senior executive of Basic Resources international Limited, Mr. Park was closely involved 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. He remained a member of the board of directors of Basic Resources international Limited until the company was sold in 1997. Mr. Park is also a member of the board of directors of energy Holdings. Mr. Park has also been involved in oil and gas projects in california, Louisiana, Argentina, Yemen and china. Mr. Park is a member of the AAPG and sPe and has lived in Latin America since 2002. BoARd of diRectoRs Gerald Eugene 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, where he served as senior Vice President and General counsel. He later formed the Globe Resources Group, a private venture firm whose subsidiaries provided seismic acquisition and processing, well rehabilitation services, sophisticated logistical operations and submersible pump works for Lukoil and other companies active in Russia during the 1990s. Mr. o’shaughnessy is also founder and owner of Boe Midstream, LLc, which owns and operates the Bakken oil express, the largest crude by rail terminal in North dakota, serving oil producers and marketing companies active in the Bakken shale oil play. over the past 25 years, Mr. o’shaughnessy has also founded and operated companies engaged in banking, wealth management products and services, investment desktop software, computer and network security, and green clean technology, as well as other venture investments. 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 instituteand is a member of the intercontinental chapter of Young Presidents organization and World Presidents’ organization. Pedro 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 Gulisano | Non-Executive Director Mr. Gulisano has been a member of our board of directors since July 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 coNicet, 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. Mr. Gulisano is also an independent consultant on oil and gas exploration and production. 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 a 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. in 1999, Mr. Pavez co-founded eventures, an internet company. 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. over the last few years he has been a board member of several companies, including Quintec, enaex, cti and frimetal. 228 Annual Report 2015 CONTENTS DIRECTORS, SECRETARy & ADVISORS 4 13 18 20 22 24 Letter to Shareholders Business Approach and Guidelines 2015 Performance Our Strengths Our Approach Our Value System 27 Form 20-F 172 Consolidated Financial Statements 228 229 Board of Directors Directors, Secretary & Advisors Directors Gerald Eugene O’Shaughnessy (Chairman) James Franklin Park (Chief Executive Officer and Deputy Chairman) Peter Ryalls (Non-Executive Director) Juan Cristóbal Pavez (Non-Executive Director) Carlos Gulisano (Non-Executive Director) Bob Bedingfield (Non-Executive Director) Pedro Aylwin (Executive Director) Registered Office 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 Pedro Aylwin Corporate Offices Director of Legal and Governance and Corporate Secretary Counsel to the Company Davis Polk & Wardwell LLP as to New York Law 450 Lexington Avenue New york, Ny 10017 USA Solicitors to the Company Cox Hallett Wilkinson as to Bermuda Law Cumberland House 9th Floor, 1 Victoria Street Hamilton HM11 - Bermuda P.O. Box HM 1561 Hamilton HMFX - Bermuda Independent Auditors Price Waterhouse & Co. S.R.L. Bouchard 557, Floor 8 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 ANNUAL REPORT 2015 5 1 0 2 T R O P E R L A U N N A k r a P o e G ANNUAL REPORT 2015 WWW.GEO-PARK.COM EXPLORER OPERATOR CONSOLIDATOR

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