Geopark Ltd
Annual Report 2014

Plain-text annual report

ANNUAL REPORT 2014 EXPLORER OPERATOR CONsOLidATOR CONTENTS 2 10 14 16 18 21 Chairman / CEO Letter Business Guidelines 2014 Performance Our Strengths Our Approach Form 20-F 244 Board of Directors Oil and Gas Production Oil and Gas Reserves BOTTOM LiNE 25 20 15 10 05 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 150 120 90 60 30 0 e o b M M n i 2009 2010 2011 2012 2013(1) 2014(1) 2009 2010 2011 2012 2013(1) 2014 2014(2) Oil Gas Oil Gas Total Revenues Adjusted EBITDA 500 400 300 200 100 $ s U M M n i 0 250 200 150 100 50 0 $ s U M M n i 2009 2010 2011 2012 2013(1) 2014(1) 2009 2010 2011 2012 2013(1) 2014(1) Oil Gas (1) including full year Oil and Gas Production, Revenues, Adj. EBiTdA and year-end Reserves corresponding to the Manati Field that closed in March 31, 2014. (2) including Peru. dear Fellow shareholders: in 2014, our first year on the NYsE, GeoPark had a record year – with Our total asset value also continued on its upward growth path. more oil and gas found and produced, our strongest financial results The net present value of our independently certified 2P reserves to date, an increase in our underlying asset value (both on a total and increased by 32% to $1.7 billion (with Peru), even after resetting our per share basis), an expanded development and exploration project reserve values at the new lower oil price scenario. (This figure does drilling inventory, a more capable organization, and the strategic not include any values for our sizeable exploration resource portfolio.) move into our fifth country – giving us one of the broadest and most Evaluating our asset values on a per share basis from year to year attractive upstream platforms in Latin America. despite a crushing allows us to show the relative underlying value growth for each decline in oil prices during the latter part of the year, we are pleased shareholder. One internal relative performance measurement (the to report that all of our principal goals were met or exceeded. NPV10 of our certified risked 3P reserves, adjusted by net debt and minority interests, and divided by the number of outstanding shares) For the ninth consecutive year, our key performance measurements indicates our oil and gas asset value per share increased by recorded gains. Operationally, our oil and gas production increased approximately 28% from 2013 to 2014 (all within the context of 20% to approximately 20,500 boepd – led by our continued success using a significantly reduced oil price forecast). with the drill bit (75+% success rate out of 51 wells drilled). A key discovery was the large Tigana oil field in Colombia, representing a GeoPark continues to be uniquely positioned in Latin America with a new Llanos Basin geological play type introduced by our geoscience self-funding organic platform consisting of 31 hydrocarbon blocks team, with lots of running room for further production growth. covering 6 million acres in 12 proven hydrocarbon basins in 5 GeoPark’s total certified proved and probable oil and gas reserves in countries (Colombia, Chile, Brasil, Argentina and Peru) consisting of a 2014 were up 31% to 92 million boe, and up 74% to 122 million boe rich and balanced mix of production, development, exploration including our Morona Block acquisition in Peru. The exploration and unconventional resource projects – and the team to make it resource potential on our blocks is estimated to be 500 million boe work. This platform, which has underpinned our consistent growth to 1 billion boe. track record to date, also proved critical in the current oil price downturn by giving us the tools and options necessary to navigate Financially, despite the 50+% drop in oil prices, our revenues were through the turbulence successfully. up 27%, Adjusted EBiTdA increased 32%, and we ended the year with approximately $130 million in cash. 2 Annual Report 2014 LETTER TO sHAREHOLdERs Any industry / business would be impacted by a halving of its base resulting in meaningful operating, G&A and capital costs reductions; product price – and the new low oil price environment is the including shut-in of marginal fields, third party contract and fee appropriate lens through which to evaluate any oil and gas company reductions, organizational restructuring and voluntary senior in the short term. in GeoPark, we decided to act fast and, in late 2014, management and Board salary reductions. (Our cash cost base in immediately began doing all that was necessary to prepare the 1Q2015 already reflects a 33% reduction from the previous year.) Company for a sustained low oil price environment of $45-50 per barrel through 2015 and 2016. Our plan is both defensive and stay Agile: Continuous monitoring and adjustment of work programs offensive, with an emphasis on cash preservation, flexibility, and – up or down – as necessary. The existing and ready inventory of new opportunities. Key elements include: organic projects provides the opportunity of expanding our program with improving cost savings and/or oil prices. Conservative Approach: Protect our balance sheet and preserve cash for an extended period by significantly reducing, deferring and Build for Long Term: Protect critical assets, tools and capabilities renegotiating work programs – and match our work and investment necessary for long term success and stay in hunt for potential value programs with forecasted cash flows. (Our agility was demonstrated dislocation opportunities. Continue moving forward with active new by an 84% capital investment program reduction from 4Q2014 project and business opportunity portfolio and develop new third to 1Q2015.) party side-by-side funding. Capital Allocation discipline: selectively allocate capital to the GeoPark’s ability to adjust quickly to this new lower oil price optimal projects under current conditions by prioritizing lower-risk, environment, and stay in position for continued growth, speaks higher netback and quicker cash flow generating projects. (GeoPark’s loudly to the resilience, capabilities and experience of our team. attractive asset base generated over 80 potential projects for 2015, it also demonstrates the strength of our underlying business model from which the work program was selected based on a ranking of and risk-managed approach, which continuously prepares for technical, economic and strategic considerations.) the uncertainties in our industry. do More for Less: Aggressively attack each and every cost throughout our operations and organization – both internal and external – Annual Report 2014 3 Business Platform and Outlook GeoPark’s vision to build the leading Latin American oil and gas representing a 134% increase from 2013. (These reserve figures independent is led by a technical approach. We identify the proven do not include the recent Tilo oil field discovery in 1Q2015.) hydrocarbon basins where we want to operate – based on geological, Estimated exploration resources for our Colombian asset base are infrastructure and regulatory factors – and then work to establish 77-155 million boe. a strategic position in these targeted regions. The Llanos 34 Block, operated by GeoPark, continues to lead our Our systematic expansion to date has resulted in building stable and growth in Colombia with six new oil field discoveries: Max, Tarotaro, growing businesses in five countries, managed by reputable and Aruco, Tua, Tilo, and Tigana oil fields. The Tigana oil field contains capable local teams, with supporting production and cash flows, gross certified 3P oil reserves of 69 million barrels to date. in 2014, attractive underlying reserves and resources, and inventories of new project acquisitions, both operated by GeoPark, included new project opportunities. Our independent country businesses are the CPO-4 Block (50% Wi) in the Llanos Basin and on trend with the further enhanced by being tied together by an overall corporate prolific Llanos 34 Block; and the ViM-3 Block (100% Wi) in organization, which improves efficiencies, reduces costs the Lower Magdalena Valley, a lightly explored high potential oil with operational and financial synergies, controls quality, pushes and gas block. performance, and can more effectively allocate capital to the best shareholder value-adding projects. in 2015, we currently plan to drill 5-6 wells – primarily in the Llanos 34 in 2014, we carried out a $240 million investment program – funded explore 1-2 new identified prospects, including one exploration well Block to further develop the Tigana, Tilo and Tua oil fields and to by our own cash flows – to continue growing our businesses. For on our new CPO-4 Block. 2015, and in consideration of the new lower oil price environment and our cash preservation objective, we are planning a self-funded Chile Business $60-70 million work program (a 75% reduction from 2014). This program consists of drilling of 5-6 new wells, new seismic surveys and GeoPark first proved our business model in Chile where we became new facility construction; and is balanced between exploration (25%) Chile’s first private oil and gas producer. From a ‘flat-footed’ start-up and development (75%) and spread approximately between in 2006, we built a solid business with current production of Colombia (60%), Chile (10%), Peru (14%), Argentina (6%) and Brazil approximately 4,500 boepd, 2P (PRMs) reserves of approximately 46 (10%). As a result of realized benefits from our rapid adjustments million boe and 6 blocks with approximately 1.0 million prospective to the lower oil price, we are now in a position to reevaluate this acres – which include 220-330 million boe of exploration and work program and look for new growth opportunities. unconventional resources. Briefly looking at each of our businesses: Our Tierra del Fuego 2014 drilling program resulted in the discovery Colombia Business of 6 oil and gas fields, but, we were unable to convert those finds into meaningful production gains and consequently total production declined in Chile. Our Fell Block drilling program resulted in GeoPark continues to create excellent success in Colombia where the discovery of the Ache gas field, which is targeted to be put on we have discovered eight new oil fields – including pioneering a new production during the last quarter of 2015. geological play-type for the Llanos Basin – and have increased production in two years from approximately 2,500 bopd to nearly during 2015, we will continue to operate and produce from 26,000 bopd gross (12,000 bopd net to GeoPark) today. Our 2P our extensive land base in Chile, with new drilling expected to reserves in Colombia increased to 39 million boe at year-end 2014, re-start in 2016. 4 Annual Report 2014 LETTER TO sHAREHOLdERs Annual Report 2014 5 Brazil Business Argentina Business Our Brazil business represents a strategic risk-balanced base with a Our team has strong technical and operational experience in fully developed secure cash flow producing asset (a 10% non- Argentina and we believe the country has an attractive subsurface operated interest in Brazil’s largest producing gas field: the Manati potential. Historically, our investment activities have been minimal; field) and nine exploration blocks (100% operated interests) in although we continue looking for the right assets under the onshore mature proven hydrocarbon basins (Potiguar, Reconcavo, right conditions. Parnaiba and sergipe Alagoas). Estimated exploration resources for our Brazilian asset base are 40-80 million boe. in 2014, we relinquished two non-productive blocks in the in 2014, GeoPark carried out seismic surveys on our blocks in the round to acquire a non-operated 18% interest in two blocks with Reconcavo and Potiguar Basins. Following seismic interpretation, our partner Pluspetrol. in 2015, we will carry out a seismic we have delineated and defined oil prospects, which we are targeting survey in an effort to delineate an attractive new shallow oil play to drill in 2016. in 2015, we are completing the construction of the (20-30 million barrel potential) in the Neuquén Basin. Mendoza Province and also participated in the Mendoza bidding compression plant for the Manati field. 6 Annual Report 2014 Peru Business LETTER TO sHAREHOLdERs The Marañón Basin in Peru, one of the most prolific hydrocarbon reserves and exploration resources. GeoPark has designed a phased basins in Latin America (with over a billion barrels of oil produced), work program that permits a step-by-step development to put the has been a target region for GeoPark and, in 2014, we succeeded in situche Central field into production initially through a long-term test positioning ourselves through the acquisition of an operating 75% to begin generating cash flow. The transaction is subject to Peruvian interest in the Morona Block from Petroperu. Morona is a large block, regulatory approval, which is targeted for 2H2015. Our work program which contains both the discovered situche Central oil field (two in 2015 is expected to consist of certain field base improvements tested wells and certified gross 3P of 83 million barrels), with the and continuation of environmental assessments. opportunity for near term cash flow, and a big exploration potential (200-500 million barrels) with several high impact plays and prospects. This is a potentially transformational acquisition for GeoPark and a great strategic fit that significantly increases our overall inventory of Annual Report 2014 7 New Projects in parallel with our conservative operating approach through the And, our thanks and appreciation to our shareholders – long term lower oil price environment, we remain on the offensive to acquire and new – who have joined us and believed in and supported our attractively-valued new oil and gas upstream opportunities in Latin project. since joining the NYsE, we are increasing our efforts to talk America and are actively pursuing projects in the countries where with you, as well as, share our story with a wider investor base. we currently have operations, that is, Colombia, Chile, Brasil, As always, your comments and recommendations are welcome Argentina and Peru. The new oil price environment is forcing all and appreciated. We invite you to visit us in the field or at any of our companies to reevaluate their portfolios and pushing the larger offices to know us better and learn first-hand how we work. groups to accelerate their divestment programs. We look forward to delivering and reporting to you on our results We are also making efforts to establish a new platform in Mexico, in 2015. which has always represented a big prize, and where current rapidly advancing regulatory reforms are now opening the door for private sincerely, companies to access some of Mexico’s highly attractive hydrocarbon assets – many of which would be an excellent fit for GeoPark’s approach and skillset. Thank You Our sincere thanks to all the men and women in GeoPark for the Company you are building, for your trust of each other and for the unique spirit that continuously propels us forward. Your heart and professionalism were again put to the test and on display by the Gerald E. O’Shaughnessy quick actions undertaken to adjust to the rapid changes in world oil Chairman prices. Our team has created an enduring culture in GeoPark, which has become our ‘secret weapon’ and the catalyst behind our proud record of safe, clean, neighborly, transparent and successful operations. Our gratitude especially 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 Our thanks to our Board of directors for your continuous efforts in helping GeoPark improve and grow. in addition to significant corporate governance responsibilities, GeoPark’s Board members spend substantial time working directly with our teams, sharing their experience, and traveling to our different operations. We express many thanks to steve Quamme for his service on our Board and strong continuing support as a shareholder. We also are very pleased to welcome Bob Bedingfield to our Board and as our Audit Committee Chairman with his extensive financial and business experience. 8 Annual Report 2014 LETTER TO sHAREHOLdERs Annual Report 2014 9 Business Guidelines strategic Context GeoPark’s objective is to create value by building the leading Latin in contrast to many areas of the world, the environment and American upstream independent oil and gas company. By this, we resources for operating and funding a business are welcoming and mean an action-oriented, persistent, aware and caring company with increasingly more feasible. Furthermore, numerous good oil and gas the best ‘shareholder value-adding’ oil and gas assets. assets in Latin America are available, undervalued and at very attractive prices now. We believe the energy business – specifically the upstream oil and gas industry – is one of the most exciting, necessary, and GeoPark has been conservatively built for the long term. We did not economically-rewarding businesses today. No undertaking or society start with a short term ‘exit strategy’ in mind and we have focused on can advance without the supply of energy, and energy remains the building a team and sustainable business. Our approach has required critical element in allowing people to better their lives. Much of the patience in order to create the necessary foundation, but it has world still lacks adequate energy supplies for the most basic needs enabled us to stay solidly ‘in the game’ and be positioned to now and demand is continually increasing. Although new exciting have the chance to grab the bigger prizes. technologies and sources are being developed, oil and gas is the most reliable energy source and will be required to support over The founders and our management team have a substantial part of half of our planet’s continuous and rising energy needs far into our net worth invested in GeoPark. None of the founders have ever this century. sold a share of GeoPark stock. in fact, we have been stock buyers over time (including in the NYsE iPO). The management team has no We believe the best places for us to find and develop hydrocarbons special class of stock or arrangements that benefit us differently from are in areas around the world where oil and gas have already any other shareholder other than our salaries and stock performance been discovered, but which for economic, technical, funding or other incentive programs. The entire GeoPark team (100% of our reasons have been inadequately developed or prematurely employees have received GeoPark share awards) is solidly aligned abandoned. These projects have proven hydrocarbon systems, with all of our shareholders to build real and enduring value for valuable technical information, existing infrastructure, and, in many every share of GeoPark. cases, unexploited low-risk exploration and re-development opportunities. By applying new technology and investment, creating Opportunity Enhancement and Risk diversification stable markets and better economic conditions, and/or more efficient operations, an under-performing or bypassed asset can be converted By its very nature, the upstream oil and gas business represents the into an attractive economic project. Work in these proven areas undertaking of risk in search of significant rewards. To succeed, an also frequently opens up exciting new hydrocarbon resources in new oil and gas company must effectively identify and manage prevailing 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 track record is evidence of our success in effectively balancing risk types of opportunities throughout the region. Latin America ranks as among the subsurface, geological, funding, organizational, market, one of the highest potential hydrocarbon resource regions in the price, partner, shareholder, regulatory and political environments. world and its economies are thirsty for new energy. Historically, it For example, GeoPark was able to respond constructively to the has been dominated by larger major and national oil companies, with 2008/9 financial crisis and, now again, to the 2015 oil price volatility. the presence of only a modest number of more-agile independent companies. (North America is home to thousands of independent We believe the best results in the upstream business are achieved oil and gas operators, whereas Latin America, an area substantially with a larger scale portfolio approach with multiple attractive projects larger and with greater resource potential, has only a handful of in multiple regions managed by talented oil and gas teams. This independents taking advantage of available opportunities.) diversification reflects both a defensive and offensive approach. 10 Annual Report 2014 BUsiNEss GUidELiNEs Capabilities it is protective of any downside because the collective strength of Our experience in the oil and gas business has repeatedly our projects limits the negative impact of any underperforming asset demonstrated the need for good people with commitment and real or timing delay. it also has an exciting multiplier effect on the oil and gas know-how. We believe in and have experienced the potential upside because of the increased number of opportunities amazing capacity of people to excel in an environment of expanding independently marching ahead. These represent important opportunity and trust. GeoPark is blessed to have an incredible group advantages given the nature of the oil exploration and production of men and women who truly work day and night to make us better business. in every way. Our results speak to the daily heroics (mostly unseen) by our team that keep us together and have moved us consistently Our country businesses are managed by experienced local closer to our goals. professionals and teams with respected reputations. They know both the specific subsurface rocks and conditions and the above- Our record of delivery is based on three fundamental and distinct skill ground operating and business environments in each region sets – as Explorers, Operators and Consolidators – which we deem and give us the characteristics of a local company. Our pride and critical for enduring success in the oil and gas business. Our team has care in how we act and perform in our home regions are key consistently demonstrated the science and creativity to find elements of our success. hydrocarbons in the subsurface, but also the muscle and experience to get the oil and gas out of the ground and profitably to market. These generally independent businesses are further enhanced by Our attractive asset portfolio is evidence of our ability to acquire good being tied together by an overall corporate organization, which projects in the right basins in the right countries with the right improves efficiencies, reduces costs with operational and financial partners and at the right price. synergies, controls quality, and can more effectively raise capital for our projects. it also is a source for new technologies and ideas Today, we have an amazing team of employees from Colombia, Chile, to spread from one region to another. For example, our team Brasil, Argentina and Peru – each of whom joined GeoPark with introduced a new geological play-type to the Llanos Basin in the purpose of building a unique and special company that is Colombia (an area that has been explored for more than 75 years) prepared to handle challenges and seize opportunities. As a quickly that resulted in multiple new oil field discoveries, and new oil growing company, we have repeatedly seen individuals technology to the Magallanes Basin in Chile. step-upto the new responsibilities presented – and we have a deep importantly, through effective and controlled capital allocation, our projects within each country business can be ranked against each The international upstream oil and gas business is not for the other on economic, technical and strategic criteria and, therefore, fainthearted or easily discouraged. Time-after-time, the GeoPark ensure our capital resources flow to the highest performing and most team has been able to push ahead to find solutions where and powerful leadership team taking GeoPark to the next level. attractive projects. often others have given-up or failed. This is the engine and fire of our growth and the true long term intangible value of our Company. We believe this business approach makes GeoPark a more attractive We are immensely grateful to all these men and women for their investment vehicle for all our shareholders – with a strong foundation professionalism, discipline, unity and heart. to minimize any downside, a big upside through multiple growth opportunities, and an overall organizational system to more efficiently run and grow the individual businesses. GeoPark’s model allows our investors to be exposed to and benefit from the results of multiple supporting and aligned businesses across diverse geologies and geographies. Annual Report 2014 11 New Projects and Countries We are excited about potential new business opportunities in Latin a detailed discounted cash flow (dCF) valuation. We also consider the America with its high resource potential, attractive business option value or strategic benefits of a project when entering a new environment, and limited competition. We are actively pursuing new region. We do not buy assets on simplified ‘$ per barrel’ metrics which projects in targeted proven hydrocarbon basins throughout the region we believe do not properly account for multiple factors (including – selected in consideration of geological, infrastructure and regulatory technical, cost, tax, and time) that impact the economics of oil and gas factors – with our principal efforts in Colombia, Chile, Brasil, Argentina, projects. We also avoid markets or ‘bubbles’ when assets are over-priced. Peru and Mexico. With our overall growth targets and portfolio approach, new project Culture acquisitions are an important part of our business. Our acquisition ‘Creating Value and Giving Back’ is our motto and represents GeoPark’s efforts begin with a technical approach to define the hydrocarbon market-based approach to align our business objectives with our core basins where our geological and engineering teams identify an values and responsibilities. Our in-house designed program, titled attractive potential. After screening for political risks, our new business s.P.E.E.d., targets and integrates the critical elements – safety, teams proactively ‘scratch and dig’ to locate interests or opportunities Prosperity, Employees, Environment and Community development – within those areas and to establish a position. it is a long term and necessary to make our total business plan work. Only by succeeding continuous effort and we have been building an attractive inventory of equally in each of these interdependent areas can we realize our overall new projects in the region over the last ten years, aided by our team’s success and ambitions. This is important in every country where we 25+ year experience in Latin America. operate, and we make every effort to achieve the most effective governance, full compliance and consistent transparency with all Our focus is always to build a larger scale balanced portfolio that relevant authorities. Not only does this allow us to be a more successful includes lower-risk short term cash flow generating properties, mid business enterprise over the long term, it reflects our pride in carrying term medium-risk development projects, and longer term higher-risk out an important mission in the right way. The men and women of big upside projects. This permits steady secure growth with GeoPark care passionately about how our Company acts – both an opportunity for accelerated high growth ‘home-runs’ from the internally and externally – and we all consider our culture to be our core bigger projects. asset and the prime source of our past success and future opportunity. Good oil and gas partners are a key element of our new business efforts The world is continuously moving in a more regulated direction with and we like to balance our acquisition risk by including experienced higher expectations, and to be able to operate in this new environment partners in our new projects. We have developed a long term strategic is a fundamental part of business today. We believe that GeoPark’s alliance with LG to build a portfolio of upstream assets across Latin ability to meet these challenges and perform to or beyond these ever America and the international Finance Corporation (iFC) of the World increasing standards represents a competitive advantage for the future. Bank is a long term principal shareholder of (and sometimes lender to For example, the manner of, results from, and impact on the and working interest partner of) GeoPark. We also have developed long communities of our overall work in Chile provided the rationale and term relationships with the national oil companies where we operate, support for the government and regional community to allow us to such as ENAP in Chile, Ecopetrol in Colombia, Petrobras in Brazil, YPF expand our project into new areas. it can also be meaningful and fun, in Argentina and Petroperu in Peru. such as with our full scholarships targeting young women, in the local communities near our field operations, for training in the sciences. Critical to the success of any new project is to conduct a thorough technical and economic analysis prior to acquiring any new asset. We The iFC of the World Bank, our long time shareholder, has been a make sure we understand the project, its risks and its value – and we buy constructive force in helping us operate and manage our business in right. it is difficult to turn a faulty or overpriced project into a good consideration of the environment and communities around us. The iFC business. Following intensive geological, geophysical, engineering, further assists us by carrying out annual audits and physical site visits of operational, legal and financial analyses and due diligence, we perform both our regulatory compliance and best-practices approach. 12 Annual Report 2014 BUsiNEss GUidELiNEs Annual Report 2014 13 2014 PERFORMANCE Key Operational Results Key Financial Results Key Strategic Results Oil and Gas Revenues Up 27% New York Stock Exchange Production Up 20% Revenues increased to $428.7 million. iPO on NYsE in February 2014, raising Average oil and gas production increased to 20,557 boepd. Adjusted EBITDA Up 32% approximately $100 million. Peru Entry 2P Reserves Up 74% Adjusted EBiTdA increased to Established fifth country platform Certified oil and gas P1 reserves $220.1 million. Adjusted EBiTdA per through the acquisition of the Morona up 116% to 62.9 mmboe and boe equaled $33. Block in partnership with Petroperu 2P reserves up 74% to 122.3 mmboe (including Peru). 75% Drilling Success 51 new wells drilled with a success rate of over 75%. Tigana Oil Field Discovery Tigana oil field discovery in Llanos Block in Colombia (69 mmbo 3P reserves). Exploration Resources Expanded Exploration resources portfolio grew to 500 MM to 1.0 billion boe. Cash Resources (GeoPark will operate with a 75% Wi). $127.7 million at year-end. Expansion of Colombian Portfolio Capital Expenditures 2014 capital expenditure program of $238 million. Net Profit Addition of the CPO-4 Block (GeoPark will operate with a 50% Wi) in Llanos Basin in partnership with sK Group, and the ViM-3 Block (GeoPark will operate with a 100% Wi) in Lower Profit for the year equaled Magdalena Basin. $15.9 million. Debt Maturity Re-Balancing Argentinean Portfolio Addition of sierra del Nevado and Long term debt maturity profile Puelen Blocks (non-operated with an with over 80% of indebtness 18% Wi) in partnership with Pluspetrol due in 2020. Total gross debt to in the Neuquen Basin, and Reserve Value Increased 32% Adjusted EBiTdA is 1.7x, and relinquishment of the non-productive 2P reserve NPV increased to represents 22% of consolidated Cerro doña Juana and Loma $1.7 billion (including Peru). 2P NPV10 (including Peru). Cortaderal Blocks. 2009 2008 2005 2006 2007 14 Annual Report 2014 2014 Oil Gas 2013 2012 2011 2010 21 20 19 18 17 16 15 14 13 12 11 10 09 08 07 06 05 04 03 02 01 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 Annual Report 2014 15 OUR sTRENGTHs M E X I C O KNOw-HOw strong Team, Capabilities, Approach and Culture. ASSETS diversified Risk-Balanced Asset Base with Proven Value, scale and Upside. TRACK RECORD Consistent Operational and Financial Growth / Ability to Unlock Value from Assets. CAPITAl supporting Cash Flow, Access to Funding and strategic Partners. GROwTH PlATFORM High-impact Portfolio of Organic and New Project Opportunities. (*) 2P Reserves – PRMs dec. 2014. 16 Annual Report 2014 C Ol O M B I A 38.6* MMBOE P E R U 30.2* MMBOE B R A Z Il 7.3* MMBOE P A CiFiC O C E A N A T L A N TiC O C E A N A R G E N T I N A C H IlE 46.2* MMBOE Asset Types Production Assets development Assets Exploration Assets Unconventional Resource Assets New Project Opportunities Annual Report 2014 17 OUR APPROACH GeoPark has been built around five fundamental and distinct capabilities: Explorer: 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. OPERATOR Consolidator: 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. 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 RISK MANAGEMENT CULTURE 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. 18 Annual Report 2014 Annual Report 2014 19 20 Annual Report 2014 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 x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2014 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 to For the transition period from 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. Common shares: 57,790,533 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No 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 x 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. x 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: Large accelerated filer o Accelerated filer x US GAAP o International Financial Reporting Standards as issued by the International Accounting Standards Board x 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. o Item 17 o 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 x No Other o 165 165 165 165 165 165 169 169 169 171 171 171 171 GeoPark Limited Table of contents PRESENTATION OF FINANCIAL AND OTHER INFORMATION FORWARD-LOOKING STATEMENTS ENFORCEMENT OF JUDGMENTS 23 26 27 D. Selling shareholders E. Dilution F. Expenses of the issue 28 PART I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS28 28 A. Directors and senior management ITEM 10. ADDITIONAL INFORMATION A. Share capital B. Memorandum of association and bye-laws 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 22 GeoPark 20F 28 28 28 28 28 28 28 32 32 33 61 61 64 129 129 130 130 130 147 151 151 151 151 151 152 152 157 159 160 161 161 161 162 163 164 164 164 164 165 165 165 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 172 ABOUT MARKET RISK ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 172 172 A. Debt securities B. Warrants and rights C. Other securities D. American Depositary Shares 172 172 172 173 PART II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 173 173 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 173 173 173 173 173 173 173 174 174 174 ITEM 16. [RESERVED] ITEM 16A. Audit committee financial expert ITEM 16B. Code of Conduct ITEM 16C. Principal Accountant Fees and Services 174 ITEM 16D. Exemptions from the listing standards for audit committees 174 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 175 175 177 177 175 180 176 177 177 Index to Consolidated Financial Statements 182 Presentation of Financial and Other Information Certain definitions Unless otherwise indicated or the context otherwise requires, all references • “Petroperú” are to Petróleos de Perú S.A., a sociedad anónima, incorporated under the laws of Peru. in this annual report to: • “Rio das Contas” are to Rio das Contas Produtora de Petróleo Ltda., a limited • “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words liability company incorporated under the laws of Brazil; of a similar effect, are to GeoPark Limited (formerly GeoPark Holdings • our “Brazil Acquisitions” are to our Rio das Contas acquisition, which Limited), an exempted company incorporated under the laws of Bermuda, we completed on March 31, 2014, our award of two new concessions by the together with its consolidated subsidiaries; ANP, one of which is subject to the entry into the concession agreement, • “Agencia” are to GeoPark Latin America Limited Agencia en Chile, and our award of seven new concessions by the ANP, in Brazil; an established branch, under the laws of Chile, of GeoPark Latin America • “Chile” are to the Republic of Chile; Limited, an exempted company incorporated under the laws of Bermuda; • “GeoPark Latin America” are to our subsidiary GeoPark Latin America Limited, an exempted company incorporated under the laws of Bermuda; • “Colombia” are to the Republic of Colombia; • “Brazil” are to the Federative Republic of Brazil; • “Argentina” are to the Argentine Republic; • “GeoPark Fell” are to our subsidiary GeoPark Fell S.p.A., a sociedad por • “Peru” are to the Republic of Peru; acciones incorporated under the laws of Chile; • “US$,” “$” and “U.S. dollars” are to the official currency of the United States • “GeoPark Chile” are to our subsidiary GeoPark Chile S.A., a sociedad of America; anónima cerrada incorporated under the laws of Chile; • “Ch$” and “Chilean pesos” are to the official currency of Chile; • “GeoPark Colombia” are prior to our internal corporate reorganization • “Col$” and “Colombian pesos” are to the official currency of Colombia; of our Colombian operations, to our subsidiary GeoPark Colombia S.A., • “GBP” are to the official currency of the United Kingdom; a sociedad anónima cerrada incorporated under the laws of Chile and subsequent to such reorganization, to GeoPark Colombia Coöperatie U.A., a cooperative duly incorporated under the laws of the Netherlands; • “AR$” 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 • “GeoPark Colombia S.A.S.” are to our subsidiary GeoPark Colombia S.A.S., the International Accounting Standards Board, or IASB; a sociedad anónima simplificada incorporated under the laws of Colombia, • “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels which absorbed Winchester, Luna and Cuerva and their Colombian branches Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis); by merger and assumed all rights and obligations of each; • “CNPE” are to the Brazilian National Council on Energy Policy (Conselho • “Winchester” are to our subsidiary Winchester Oil and Gas S.A., now Nacional de Política Energética); GeoPark Colombia PN S.A. Sucursal Colombia, a Colombian branch • “ANH” are to the Colombian National Hydrocarbons Agency (Agencia of a sociedad anónima incorporated under the laws of Panama, which Nacional de Hidrocarburos); merged into GeoPark Colombia S.A.S.; • “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional • “Luna” are to our subsidiary La Luna Oil Company Limited S.A., a sociedad de Petróleo) anónima incorporated under the laws of Panama, which merged into • “economic interest” means an indirect participation interest in the GeoPark Colombia S.A.S.; • “Cuerva” are to our subsidiary GeoPark Cuerva LLC, formerly known net revenues from a given block based on bilateral agreements with the concessionaires; and as Hupecol Caracara LLC, a limited liability company incorporated under the • “working interest” means the right granted to the lessee of a property laws of the state of Delaware, which merged into GeoPark Colombia S.A.S.; to explore for and to produce and own oil, gas, or other minerals. The • “LGI” are to LG International Corp., a company incorporated under the working interest owners bear the exploration, development and operating laws of Korea; costs on either a cash, penalty or carried basis. • “Morona Block Acquisition” are to our pending Morona Block acquisition in Northern Peru, which we expect will close in 2015 following regulatory approvals. • “Panoro” are to Panoro Energy do Brasil Ltda., a limited liability company incorporated under the laws of Brazil and a subsidiary of Panoro Energy ASA, a company incorporated under the laws of Norway, with assets in Brazil and Africa; • “Perupetro” are to Perupetro S.A., the Peruvian State company, responsible for promoting, negotiating, underwriting and monitoring contracts for exploration and exploitation of hydrocarbons in Peru. GeoPark 20F 23 Financial statements Financial statements Our consolidated financial statements This annual report includes our audited consolidated financial statements as Non IFRS financial measures Adjusted EBITDA Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by management and external users of our financial statements, such as of December 31, 2014 and 2013 and for each of the years ended December industry analysts, investors, lenders and rating agencies. 31, 2014, 2013 and 2012, or our Annual Consolidated Financial Statements. Our Consolidated Financial Statements are presented in U.S. dollars and have income tax, depreciation, amortization and certain non-cash items such as been prepared in accordance with IFRS, as issued by the International impairments and write-offs of unsuccessful exploration and evaluation assets, We define Adjusted EBITDA as profit for the period before net finance cost, Accounting Standards Board (“IASB”). accrual of stock options and stock awards and bargain purchase gain on acquisition of subsidiaries. Adjusted EBITDA is not a measure of profit or cash Our Annual Consolidated Financial Statements have been audited by Price flows as determined by IFRS. Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers Network, or PwC, an independent registered public accounting firm, as stated We believe Adjusted EBITDA is useful because it allows us to more in their report included elsewhere in this annual report. effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing Our fiscal year ends December 31. References in this annual report to a fiscal methods or capital structure. We exclude the items listed above from profit year, such as “fiscal year 2014,” relate to our fiscal year ended on December 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 Annual Consolidated Financial Statements as of and for the years ended 2014, 2013 and 2012, included in this annual report. 31 of that calendar year. 24 GeoPark 20F Rounding We have made rounding adjustments to some of the figures included in this annual report. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that precede them. Oil and gas reserves and production information D&M 2014 Year-end Reserves Report The information included in this annual report regarding estimated quantities of proved reserves in Brazil, Chile, Colombia and Peru is derived, in part, from estimates of the proved reserves as of December 31, 2014. The reserves estimates are derived from the report prepared by DeGolyer and MacNaughton, or D&M, independent reserves engineers, or the D&M Reserves Report, included as an exhibit to this annual report, prepared by D&M. The D&M Reserves Report was prepared by D&M for us and presents estimates as of December 31, 2014 of oil and gas reserves located in the Fell, Campanario, Flamenco and Isla Norte Blocks in Chile, La Cuerva, Llanos 32, Llanos 34, Llanos 17, and Yamú Blocks in Colombia, the interests held through Rio das Contas in Brazil in BCAM-40 Concession (Manatí) and pro-forma estimates for the Morona Block in Peru. We expect to close the pending Morona Block Acquisition in 2015. 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 (including information available from the SEC website) 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 20F 25 Forward-looking Statements This annual report contains statements that constitute forward-looking • our ability to retain key members of our senior management and key statements. Many of the forward-looking statements contained in this annual technical employees; report can be identified by the use of forward-looking words such as • competition from other similar oil and natural gas companies; “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” • market or business conditions and fluctuations in global and local demand “estimate” and “potential,” among others. for energy; Forward-looking statements appear in a number of places in this annual incidents or responses to such incidents, including the effect on the report and include, but are not limited to, statements regarding our intent, availability of and premiums on insurance; and belief or current expectations. Forward-looking statements are based on • other factors discussed under “-Item 3. Key Information-D. Risk factors” in • the direct or indirect impact on our business resulting from terrorist our management’s beliefs and assumptions and on information currently this annual report. available to our management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed Forward-looking statements speak only as of the date they are made, and or implied in the forward-looking statements due to various factors, we do not undertake any obligation to update them in light of new including, but not limited to, those identified under the section “-Item 3. information or future developments or to release publicly any revisions to Key Information-D. Risk factors” in this annual report. These risks and these statements in order to reflect later events or circumstances or to uncertainties include factors relating to: • operating risks, including equipment failures and the amounts and timing reflect the occurrence of unanticipated events. of revenues and expenses; • termination of, or intervention in, concessions, rights or authorizations granted by the Chilean, Colombian, Brazilian 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; • the volatility of oil and natural gas prices; • 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 Chile, Colombia, 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 26 GeoPark 20F Enforcement of Judgments We are incorporated as an exempted company with limited liability under such director, officer or auditor may be guilty in relation to the company. the laws of Bermuda, and substantially all of our assets are located in Chile, Section 98 further provides that a Bermuda company may indemnify Colombia, Brazil and to a lesser extent in Argentina. In addition, most of its directors, officers and auditors against any liability incurred by them in our directors and executive officers reside outside the United States, and all defending any proceedings, whether civil or criminal, in which judgment or a substantial portion of the assets of such persons are located outside is awarded in their favor or in which they are acquitted or granted relief by the United States. As a result, it may be difficult for investors to effect service the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda of process on those persons in the United States or to enforce in the United Companies Act. States judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws. Our bye-laws contain provisions whereby we and our shareholders waive any claim or right of action that we have, both individually and on our behalf, There is no treaty in force between the United States and Bermuda providing against any director or officer in relation to any action or failure to take for the reciprocal recognition and enforcement of judgments in civil and action by such director or officer, except in respect of any fraud or dishonesty commercial matters. As a result, whether a U.S. judgment would be of such director or officer. We may also indemnify our directors and officers enforceable in Bermuda against us or our directors and officers depends on in their capacity as directors and officers for any loss arising or liability whether the U.S. court that entered the judgment is recognized by the attaching to them by virtue of any rule of law in respect of any negligence, Bermuda court as having jurisdiction over us or our directors and officers, default, breach of trust of which a director or officer may be guilty in relation as determined by reference to Bermuda conflict of law rules and the to the company other than in respect of his own fraud or dishonesty. We judgment is not contrary to public policy in Bermuda, has not been obtained have entered into customary indemnification agreements with our directors. by fraud 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 No treaty exists between the United States and Chile for the reciprocal for a sum certain based on U.S. federal securities laws will not be enforceable recognition and enforcement of foreign judgments. Chilean courts, however, in Bermuda unless the judgment debtor had submitted to the jurisdiction have enforced valid and conclusive judgments for the payment of money of the U.S. court, and the issue of submission and jurisdiction is a matter of rendered by competent U.S. courts by virtue of the legal principles of Bermuda (not U.S.) law. reciprocity and comity, subject to review in Chile of the U.S. judgment in order to ascertain whether certain basic principles of due process and An action brought pursuant to a public or penal law, the purpose of which is public policy have been respected, without retrial or review of the merits of the enforcement of a sanction, power or right at the instance of the state the subject matter. If a U.S. court grants a final judgment, enforceability in its sovereign capacity, may not be entertained by a Bermuda court. Certain of this judgment in Chile will be subject to obtaining the relevant exequatur remedies available under the laws of U.S. jurisdictions, including certain (i.e., recognition and enforcement of the foreign judgment) according to remedies under U.S. federal securities laws, may not be available under Chilean civil procedure law in effect at that time, and depending on certain Bermuda law or enforceable in a Bermuda court, as they may be contrary to factors (the satisfaction or non-satisfaction of which would be determined Bermuda public policy. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violations of U.S. by the Supreme Court of Chile). Currently, the most important of such factors are: the existence of reciprocity (if it can be proved that there is no federal securities laws because these laws have no extraterritorial jurisdiction reciprocity in the recognition and enforcement of the foreign judgment under Bermuda law and do not have force of law in Bermuda. A Bermuda between the United States and Chile, that judgment would not be enforced court may, however, impose civil liability on us or our directors and officers in Chile); the absence of any conflict between the foreign judgment and if the facts alleged in a complaint constitute or give rise to a cause of action Chilean laws (excluding for this purpose the laws of civil procedure) under Bermuda law. However, section 281 of the Bermuda Companies Act and Chilean public policy; the absence of a conflicting judgment by a Chilean allows a Bermuda court, in certain circumstances, to relieve officers and court relating to the same parties and arising from the same facts and directors of Bermuda companies of liability for acts of negligence, breach of circumstances; the Chilean court’s determination that the U.S. courts had duty or trust or other defaults. jurisdiction, that process was appropriately served on the defendant and that the defendant was afforded a real opportunity to appear before the court Section 98 of the Bermuda Companies Act provides generally that a Bermuda and defend its case; and the judgment being final under the laws of the company may indemnify its directors, officers and auditors against any country in which it was rendered. Nonetheless, we have been advised by our liability which by virtue of any rule of law would otherwise be imposed on Chilean counsel that there is doubt as to the enforceability in original actions them in respect of any negligence, default, breach of duty or breach of trust, in Chilean courts of liabilities predicated solely upon U.S. federal or state except in cases where such liability arises from fraud or dishonesty of which securities laws. GeoPark 20F 27 Part I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS We have not included selected consolidated financial data as of and for the year ended December 31, 2010 in the tables below as we qualify as an emerging growth company under the Jumpstart Our Business Startups Act of 2012 or the JOBS Act and we make use of an existing accommodation for specified reduced reporting, requiring only two years of audited financial statements at the time of our initial public offering. 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, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 from our Annual 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, 2012 and 2011 and for the year ended December 31, 2011 from our Annual Consolidated Financial Statements not included in this annual report. We maintain our books and records in U.S. dollars 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, included elsewhere in this annual report. 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. 28 GeoPark 20F Statement of Income Data For the year ended December 31, 2014 2013 2012 2011 (in thousands of US$, except per share numbers) Revenue Net oil sales Net gas sales Net revenue Production costs Gross profit Exploration costs Administrative costs Selling expenses Impairment loss for non-financial assets Other operating income/(expense) Operating profit Financial results Bargain purchase gain on acquisition of subsidiaries Profit before tax Income tax Profit for the year Non-controlling interest Profit attributable to owners of the Company Earnings per share for profit attributable to owners of the Company - basic Earnings per share for profit attributable to owners of the Company - diluted(2) Weighted average common shares 367,102 61,632 428,734 315,435 22,918 338,353 221,564 28,914 250,478 (229,650) 199,084 (179,643) 158,710 (129,235) 121,243 (43,369) (48,164) (24,428) (9,430) (1,849) 71,844 (16,254) (46,584) (17,252) - 5,344 83,964 (27,890) (28,798) (24,631) - 823 40,747 73,508 38,072 111,580 (54,513) 57,067 (10,066) (18,169) (2,546) - (502) 25,784 (50,719) (33,876) (16,308) (13,516) - - 21,125 50,088 (5,195) 15,930 8,418 7,512 0.13 0.13 (15,154) 34,934 12,922 22,012 0.50 0.47 8,401 32,840 (14,394) 18,446 6,567 11,879 0.28 0.27 - 12,268 (7,206) 5,062 5,008 54 0.00 0.00 outstanding - basic 56,396,812 43,603,846 42,673,981 41,912,685 Weighted average common shares outstanding - diluted(2) 58,840,412 46,532,049 44,109,305 43,917,167 Common Shares outstanding at year-end 57,790,533 43,861,614 43,495,585 42,474,274 (1) See Note 18 to our Annual Consolidated Financial Statements. GeoPark 20F 29 Balance Sheet Data As of December 31, (In thousands of US$) Assets Non current assets 2014 2013 2012 2011 Property, plant and equipment 790,767 595,446 457,837 224,635 Prepaid taxes Other financial assets Deferred income tax Prepayments and other receivables 1,253 12,979 33,195 349 11,454 5,168 13,358 6,361 10,707 7,791 13,591 510 2,957 5,226 450 707 Total non current assets 838,543 631,787 490,436 233,975 - 8,532 36,917 13,993 13,459 127,672 200,573 1,039,116 58 210,886 164,613 - 8,122 42,628 35,764 6,979 121,135 214,628 846,415 44 120,426 150,371 - 3,955 32,271 49,620 3,443 48,292 137,581 628,017 43 116,817 122,561 3,000 584 15,929 24,984 147 193,650 238,294 472,269 43 112,231 96,615 375,557 270,841 239,421 208,889 103,569 479,126 95,116 365,957 72,665 312,086 41,763 250,652 Current assets Other financial assets Inventories Trade receivables Prepayments and other receivables Prepaid taxes Cash at bank and in hand Total current assets Total assets Share capital Share premium Other Equity attributable to owners of the Company Equity attributable to non-controlling interest Total equity Liabilities Non current liabilities Borrowings Provisions for other long-term liabilities Trade and other payables Deferred income tax 342,440 290,457 46,910 16,583 30,065 33,076 8,344 23,087 Total non current liabilities 435,998 354,964 Current liabilities Borrowings Current income tax Trade and other payables Total current liabilities Total liabilities 27,153 7,935 88,904 123,992 559,990 26,630 7,231 91,633 125,494 480,458 165,046 25,991 - 17,502 208,539 27,986 7,315 72,091 107,392 315,931 134,643 9,412 - 13,109 157,164 30,613 187 33,653 64,453 221,617 Total equity and liabilities 1,039,116 846,415 628,017 472,269 30 GeoPark 20F Cash Flow Data For the year ended December 31, 2014 2013 2012 2011 (In thousands of US$) Cash provided by (used in) Operating activities Investing activities Financing activities Net increase (decrease) in cash Other Financial Data 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, 2014 2013 2012 2011 Adjusted EBITDA(1) (US$ thousands) Adjusted EBITDA margin(2) Adjusted EBITDA per boe(3) 220,077 167,253 121,404 51.3% 33.0 49.4% 33.9 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 Annual Consolidated Financial Statements included in this annual report. (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. GeoPark 20F 31 Exchange rates In Chile, Colombia, Argentina and Peru, our functional currency is the U.S. dollar. In Brazil, our functional currency is the real. The following table presents the monthly high and low representative market rate during the months indicated. The Brazilian foreign exchange system allows the purchase and sale of Recent exchange rates of Real per U.S. dollar Low High foreign currency and the international transfer of real by any person or legal Month: entity, regardless of the amount, subject to certain regulatory procedures. October 2014 Since 1999, the Brazilian Central Bank has allowed the U.S. dollar-real exchange rate to float freely, and, since then, the U.S. dollar-real exchange rate has fluctuated considerably. Our operations in Brazil account for 15% of our consolidated assets and 8% of our revenues for the year ended November 2014 December 2014 January 2015 February 2015 March 2015 December 31, 2014. This portion of our business is exposed to losses that may April 2015 (through April 27, 2015) 2.3914 2.4839 2.5607 2.5754 2.6894 2.8655 2.9236 2.5341 2.6136 2.7403 2.7107 2.8811 3.2683 3.1556 arise from currency fluctuation, as a significant amount of our revenues, operating costs, administrative expenses and taxes in Brazil are denominated in reais. In addition, as we financed our Rio das Contas acquisition in part through our Brazilian subsidiary’s entrance into a US$70.5 million credit facility with Itaú BBA International plc, this also exposes us to exchange rate losses from the devaluation of the Brazilian reais against the U.S. dollar. Source: Central Bank of Brazil. The following table presents the average R$ per U.S. dollar representative market rate for each of the five most recent years, calculated by using the average of the exchange rates on the last day of each month during the period, and the representative year-end market rate for each of the five In the past, the Brazilian Central Bank has occasionally intervened to control most recent years. unstable movements in foreign exchange rates. We cannot predict whether the Brazilian Central Bank or the Brazilian government will continue to Real per U.S. dollar Low High permit the real to float freely or will intervene in the exchange rate market Period: through the return of a currency band system or otherwise. The real may depreciate or appreciate substantially against the U.S. dollar. Furthermore, Brazilian law provides that, whenever there is a serious imbalance in Brazil’s balance of payments or there are serious reasons to foresee a serious imbalance, temporary restrictions may be imposed on remittances of foreign 2009 2010 2011 2012 2013 capital abroad. We cannot assure you that such measures will not be taken First quarter 2014 by the Brazilian government in the future. As a result of the devaluation Second quarter 2014 that occurred in the year ended December 31, 2014, we recorded exchange Third quarter 2014 rate losses amounting to US$19.2 million in our Brazilian subsidiary. This loss was generated by the credit facility of US$70.5 million that we incurred Fourth quarter 2014 First quarter 2015 to acquire Rio das Contas in March 31, 2014. See “-D. Risk factors-Risks relating Second quarter 2015 (through April 27, 2015) to our business-Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates.” Source: Central Bank of Brazil. 1.9936 1.7593 1.6746 1.9550 2.1605 2.3409 2.2296 2.2745 2.5437 2.8702 2.9236 1.7412 1.6662 1.8758 2.0435 2.3426 2.2630 2.2025 2.4510 2.6562 3.2080 3.1556 The following tables show the selling rate for U.S. dollars for the periods Exchange rate fluctuation may affect the U.S. dollar value of any distributions and dates indicated. The information in the “Average” column represents we make with respect to our common shares. See “-D. Risk factors- the average of the daily exchange rates during the periods presented. Risks relating to our business-Our results of operations could be materially The numbers in the “Period-end” column are the quotes for the exchange adversely affected by fluctuations in foreign currency exchange rates.” rate as of the last business day of the period in question. As of April 27, 2015, the exchange rate for the purchase of U.S. dollars as reported by the Central Bank of Brazil was R$2.9236 per U.S. dollar. B. Capitalization and indebtedness Not applicable. C. Reasons for the offer and use of proceeds Not applicable. 32 GeoPark 20F D. Risk factors • the price and availability of competitors’ supplies of oil and natural gas in Our business, financial condition and results of operations could be materially captive market areas; and adversely affected if any of the risks described below occur. As a result, • quality discounts for oil production based, among other things, on API the market price of our common shares could decline, and you could lose and mercury content; all or part of your investment. This annual report also contains forward-looking • taxes and royalties under relevant laws and the terms of our contracts; statements that involve risks and uncertainties. See “Forward-Looking • our ability to enter into oil and natural gas sales contracts at fixed prices; Statements.” The risks below are not the only ones facing our Company. • the level of global methanol demand and inventories and changes Additional risks not currently known to us or that we currently deem immaterial in the uses of methanol; may also adversely affect us. Risks relating to our business • the price and availability of alternative fuels; and • future changes to our hedging policies. A substantial or extended decline in oil, natural gas and methanol prices difficult to predict future natural gas and oil price movements. For example, may materially adversely affect our business, financial condition or results recently, oil and gas prices have fluctuated significantly. From January 1, These factors and the volatility of the energy markets make it extremely of operations. 2010 to December 31, 2014, Brent spot prices ranged from a low of US$55.27 per barrel to a high of US$128.14 per barrel, NYMEX West Texas International, The prices that we receive for our oil and natural gas production heavily or WTI, crude oil contracts prices ranged from a low of US$53.45 per bbl to a influence our revenues, profitability, access to capital and growth rate. high of US$113.39 per bbl, Henry Hub natural gas average spot prices ranged Historically, the markets for oil, natural gas and methanol (which historically from a low of US$1.82 per mmbtu to a high of US$8.15 per mmbtu, US Gulf have influenced prices for almost all of our Chilean gas sales) have been methanol spot barge prices ranged from a low of US$240.34 per metric ton volatile and will likely continue to be volatile in the future. International oil, to a high of US$564.12 per metric ton. Further, oil, natural gas and methanol natural gas and methanol prices have fluctuated widely in recent years prices do not necessarily fluctuate in direct relationship to each other. and may continue to do so in the future. The prices that we will receive for our production and the levels of our from oil. Because we expect that our production mix will continue to be production depend on numerous factors beyond our control. These factors weighted towards oil, our financial results are more sensitive to movements For the year ended December 31, 2014, 86% of our revenues, were derived include, but are not limited, to the following: • global economic conditions; in oil prices. • changes in global supply and demand for oil, natural gas and methanol; As of December 31, 2014, natural gas comprised 14% of our revenues. • the actions of the Organization of the Petroleum Exporting Countries, A decline in natural gas prices could negatively affect our future growth, or OPEC; • political and economic conditions, including embargoes, in oil-producing countries or affecting other countries; particularly for future gas sales where we may not be able to secure or extend our current long-term contracts. • the level of oil- and natural gas-producing activities, particularly in the Lower oil and natural gas prices may not only decrease our revenues on a Middle East, Africa, Russia, South America and the United States; per unit basis, but also may reduce the amount of oil and natural gas that we • the level of global oil and natural gas exploration and production activity; can produce economically. In addition, changes in oil and gas prices can • the level of global oil and natural gas inventories; impact our valuation of reserves and, in periods of sharply lower commodity • the price of methanol; • availability of markets for natural gas; prices, we may curtail production and capital spending projects or may defer or delay drilling wells because of lower cash flows. A substantial or extended • weather conditions and other natural disasters; decline in oil or natural gas prices would materially adversely affect our • technological advances affecting energy production or consumption; business, financial condition and results of operations. We have historically • domestic and foreign governmental laws and regulations, including not hedged our production to protect against fluctuations in the international environmental, health and safety laws and regulations; • proximity and capacity of oil and natural gas pipelines and other oil prices. We may in the future consider adopting a hedging policy against commodity price risk, when deemed appropriate and taking into account the transportation facilities; size of our business and market volatility. GeoPark 20F 33 The current oil price crisis has impacted our operations and corporate cash we are able to generate from current operations. If we are not able strategies. to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently We face limitations on our ability to increase prices or improve margins execute our work program which would cause us to further decrease our on the oil and natural gas that we sell. As a consequence of the oil price crisis work program, which could harm our business outlook, investor confidence which started in the second half of 2014 (WTI and Brent, the main and our share price. international oil price markers, fell by approximately 50% between August 2014 and March 2015), the Company has undertaken a decisive cost cutting In addition, actions taken by the company to maximize ongoing work program to ensure its ability to both maximize ongoing work projects projects and to reduce expenses, including renegotiations and reduction of and to preserve its cash. oil and gas service contracts and other initiatives included in the cost cutting program adopted by us may expose us to claims and contingencies from The main actions that are being carried out under our 2015 cost-cutting interested parties that may have a negative impact on our business, financial program to address the oil industry price crisis include the: • reduction of our capital investment taking advantage of the flexible work program; condition, results of operations and cash flows. If oil prices continue to remain low then we may be unable to meet our contractual obligations with oil and service contracts and our suppliers. Equally, those third parties may be unable • deferment of capital projects with relevant permissions and consents from to meet their contractual obligations to us as a result of the oil price crisis, regulatory authorities and partners, as permitted by our contracts; impacting on our operations. • renegotiation of licenses and concessions, where permitted, and renegotiation and reduction of oil and gas service contracts, including drilling Unfavorable credit and market conditions, such as the global financial and civil work contractors, as well as transportation, trucking and pipeline crisis that began in 2008 or the recent decline in oil prices have affected costs; and and could continue to affect negatively the economies of the countries • improving the efficiency of our operating costs and the temporary in which we operate and may negatively affect our business, and results suspension of certain low-margin producing oil and gas fields. of operations. In 2015 we reduced our workforce significantly. This reduction streamlined Global financial crises and related turmoil in the global financial system certain internal functions and departments to meet our current needs, have had, and may continue to have, a negative impact on our business, which we expect will contribute to create a more efficient workforce in the financial condition, results of operations and cash flows. The lingering effects current economic environment. As a result, we expect to realize US$12 of the global credit crisis that began in 2008 and of financial crises generally million annually in cost savings associated with the reduction of full-time on our customers and on us cannot be predicted, which could have an impact and temporary employees, excluding onetime termination costs of on our flexibility to react to changing economic and business conditions. In approximately US$6 million in 2015. Further cost reductions are expected in 2015 due to the general addition, the recent decline in WTI and Brent, the main international oil price markers, that fell by approximately 50% between August 2014 and March 2015 and which are expected to remain volatile in the near future, may also depreciation of Latin American currencies (Colombian peso, Brazilian real, negatively affect the economies of the countries in which we operate. Chilean peso, Argentine peso and Peruvian sol), in connection with operating Any of the foregoing factors or a combination of these factors could have an and structure costs established in local currencies and also related to a adverse effect on our results of operations and financial condition. voluntary salary reduction by GeoPark’s senior management team and Board of Directors. Our preliminary capital program for 2015 calls for approximately Unless we replace our oil and natural gas reserves, our reserves and US$60 million - US$70 million to fund our exploration and development, production will decline over time. Our business is dependent on which we intend to fund through cash flows from operations and our continued successful identification of productive fields and prospects cash-in-hand. Funding for this program relies in part on oil prices remaining and the identified locations in which we drill in the future may not close to current or higher levels and other factors to generate sufficient cash yield oil or natural gas in commercial quantities. flow. Oil prices were very volatile at the end of 2014 and have remained at low levels in the first part of 2015. We have restricted activity and lowered Production from oil and gas properties declines as reserves are depleted, our planned capital expenditure for 2015 as compared to previous years. with the rate of decline depending on reservoir characteristics. Accordingly, Low oil prices affect our revenues, which in turn affects our debt capacity our current proved reserves will decline as these reserves are produced. and the covenants in our financing agreements, as well the amount of money As of December 31, 2014, our reserves-to-production (or reserve life) ratio for we can borrow using our oil reserves as collateral, as well as the amount of net proved reserves in Chile, Colombia and Brazil was 6 years. According to 34 GeoPark 20F estimates, if on January 1, 2015, we ceased all drilling and development and or Gunvor were to decrease or cease purchasing oil from us, or if any of them workovers, including recompletions, refracs and workovers, our proved were to decide not to renew their contracts with us or to renew them at a developed producing reserves base in Chile, Colombia, Argentina and Brazil lower sales price, this could have a material adverse effect on our business, would decline at an annual effective rate of 33% over the first three years, financial condition and results of operations. including 40% during the first year. In Brazil, all of our revenues from the sale of gas in the Manatí Field in Brazil Our future oil and natural gas reserves and production, and therefore our were generated from sales to Petrobras, the operator of the Manatí Field, cash flows and income, are highly dependent on our success in efficiently pursuant to a long-term gas off-take contract. See “-Item 4. Information developing our current reserves and using cost-effective methods to find or on the Company-B. Business overview-Significant agreements-Brazil- acquire additional recoverable reserves. While we have had success in Petrobras Natural Gas Purchase Agreement.” identifying and developing commercially exploitable deposits and drilling locations in the past, we may be unable to replicate that success in the In Peru, subject to government approval of GeoPark being assigned 75% future. We may not identify any more commercially exploitable deposits or in the Morona Block (also known as Lote 64), and other environmental successfully drill, complete or produce more oil or gas reserves, and the permits and if we are able to start producing oil from this block, Petroperú, wells which we have drilled and currently plan to drill within our blocks or the Peruvian national oil company has the first option but not the obligation concession areas may not discover or produce any further oil or gas or may to purchase oil produced by us in the Marona Block. not discover or produce additional commercially viable quantities of oil or gas to enable us to continue to operate profitably. If we are unable to replace Our results of operations could be materially adversely affected by our current and future production, the value of our reserves will decrease, fluctuations in foreign currency exchange rates. and our business, financial condition and results of operations will be materially adversely affected. Although a majority of our net revenues is denominated in U.S. dollars, unfavorable fluctuations in foreign currency exchange rates for certain of our We derive a significant portion of our revenues from sales to a few key expenses in Chile, Colombia, Brazil, Peru and Argentina could have a material customers. adverse effect on our results of operations. Furthermore, we have not entered, into derivative transactions to hedge the effect of changes in the In Chile, 100% of our crude oil and condensate sales are made to ENAP. For exchange rate of local currencies to the U.S. dollar. Because our consolidated the year ended December 31, 2014, sales to ENAP represented 32% of our financial statements are presented in U.S. dollars, we must translate revenues, revenues from oil and 28% of our total revenues. ENAP imports the majority expenses and income, as well as assets and liabilities, into U.S. dollars of the oil it refines and partially supplements those imports with volumes at exchange rates in effect during or at the end of each reporting period. supplied locally by its own operated fields and those operated by us. The sales contract with ENAP is commonly revised every year to reflect changes In addition, our Rio das Contas acquisition, significantly increased our in the global oil market and to adjust for ENAP’s logistics costs in the Gregorio oil terminal. As of the date of this Annual Report, we are negotiating a new agreement with ENAP with an initial term of three to six months. exposure to fluctuations in the real against the U.S. dollar, as Rio das Contas’s revenues and expenses are denominated in reais. The real has experienced frequent and substantial variations in relation to the U.S. dollar and other In addition, in Chile, in the year ended December 31, 2014, almost all of our foreign currencies. For example, the real was R$1.56 per US$1.00 in August natural gas sales were made to Methanex under a long-term contract, the 2008. Following the onset of the crisis in the global financial markets, “Methanex Gas Supply Agreement”, which expires on April 30, 2017. Sales to the real depreciated 31.9% against the U.S. dollar and reached R$2.34 per Methanex represented 6% of our consolidated revenues for the year ended US$1.00 at the end of 2008. In 2011, the real appreciated against the U.S. December 31, 2014. However, if ENAP or Methanex were to decrease or cease dollar, reaching R$1.876 per US$1.00 at the end of 2011. In 2012, however, purchasing our oil and gas, or if we were unable to renew these contracts the real depreciated, and on December 31, 2013, the exchange rate at a lower sales price or at all, this could have a material adverse effect on our was R$2.3426 per US$1.00. As of December 31, 2014, the exchange rate was business, financial condition and results of operations. R$2.6562 per US$1.00. In the first three months of 2015, the real depreciated and the exchange rate as of March 31, 2015 was R$3.2080 per US$1.00. In Colombia, for the year ended December 31, 2014, we made 40.1% of our Depending on the circumstances, either depreciation or appreciation of the oil sales to Gunvor, 31.8% to Emerald and 11.0% to Perenco, with Gunvor real could materially and adversely affect the growth of the Brazilian economy accounting for 23.0%, Emerald 18.3% and Perenco 6.3% of our consolidated and our business, financial condition and results of operations. For example, revenues for the same period. Our current sales contracts with Emerald, in 2014, we recorded exchange rate losses amounting to US$19.2 million in Perenco and Gunvor are short-term agreements. If any of Emerald, Perenco our Brazilian subsidiary that were generated by the credit facility of US$70.5 GeoPark 20F 35 million that we incurred to acquire Rio das Contas in March 31, 2014. See Our management team has specifically identified and scheduled certain “-A. Selected financial data-Exchange rates.” potential drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2014, approximately There are inherent risks and uncertainties relating to the exploration 75 of our specifically identified potential future drilling locations were and production of oil and natural gas. attributed to proved undeveloped reserves in Chile, Colombia and Brazil. These identified potential drilling locations, including those without proved Our performance depends on the success of our exploration and production undeveloped reserves, represent a significant part of our growth strategy. activities and on the existence of the infrastructure that will allow us to take advantage of our oil and gas reserves. Oil and natural gas exploration Our ability to drill and develop these identified potential drilling locations and production activities are subject to numerous risks beyond our control, depends on a number of factors, including oil and natural gas prices, the including the risk that exploration activities will not identify commercially availability and cost of capital, drilling and production costs, the availability viable quantities of oil or natural gas. Our decisions to purchase, explore, of drilling services and equipment, drilling results, lease expirations, the develop or otherwise exploit prospects or properties will depend in part availability of gathering systems, marketing and transportation constraints, on the evaluation of seismic and other data obtained through geophysical, refining capacity, regulatory approvals and other factors. Because of geochemical and geological analysis, production data and engineering the uncertainty inherent in these factors, there can be no assurance that studies, the results of which are often inconclusive or subject to varying the numerous potential drilling locations we have identified will ever be interpretations. drilled or, if they are, that we will be able to produce oil or natural gas from Furthermore, the marketability of any oil and natural gas production from our projects may be affected by numerous factors beyond our control. These Our business requires significant capital investment and maintenance factors include, but are not limited to, proximity and capacity of pipelines and expenses, which we may be unable to finance on satisfactory terms these or any other potential drilling locations. other means of transportation, the availability of upgrading and processing or at all. facilities, equipment availability and government laws and regulations (including, without limitation, laws and regulations relating to prices, sale The oil and natural gas industry is capital intensive and we expect to make restrictions, taxes, governmental stake, allowable production, importing and substantial capital expenditures in our business and operations for exporting of oil and natural gas, environmental protection and health and the exploration and production of oil and natural gas reserves. We made safety). The effect of these factors, individually or jointly, cannot be accurately US$215.2 million and US$353.0 million (including US$140.1 million in Brazil predicted, but may have a material adverse effect on our business, financial to acquire Rio das Contas, which we financed through the incurrence of a condition and results of operations. loan of US$70.5 million and cash on hand) of capital expenditures during the years ended December 31, 2013 and 2014, respectively. See “-Item 5. There can be no assurance that our drilling programs will produce oil and Operating and Financial Review and Prospects-B. Liquidity and capital natural gas in the quantities or at the costs anticipated, or that our currently producing projects will not cease production, in part or entirely. Drilling resources-Capital Expenditures” for expected capital expenditures in 2015. programs may become uneconomic as a result of an increase in our The actual amount and timing of our future capital expenditures may differ operating costs or as a result of a decrease in market prices for oil and materially from our estimates as a result of, among other things, commodity natural gas. Our actual operating costs or the actual prices we may receive prices, actual drilling results, the availability of drilling rigs and other for our oil and natural gas production may differ materially from current equipment and services, and regulatory, technological and competitive estimates. In addition, even if we are able to continue to produce oil and developments. In response to improvements in commodity prices, we may gas, there can be no assurance that we will have the ability to market increase or decrease our actual capital expenditures. We intend to finance our oil and gas production. See “-Our inability to access needed equipment our future capital expenditures through cash generated by our operations and infrastructure in a timely manner may hinder our access to oil and natural and potential future financing arrangements. However, our financing needs gas markets and generate significant incremental costs or delays in our may require us to alter or increase our capitalization substantially through oil and natural gas production” below. the issuance of debt or equity securities or the sale of assets. Our identified potential drilling location inventories are scheduled over If our capital requirements vary materially from our current plans, we may many years, making them susceptible to uncertainties that could materially require further financing. In addition, we may incur significant financial alter the occurrence or timing of their drilling. indebtedness in the future, which may involve restrictions on other financing and operating activities. We may also be unable to obtain financing or 36 GeoPark 20F financing on terms favorable to us. These changes could cause our cost Oil and gas operations contain a high degree of risk and we may not be of doing business to increase, limit our ability to pursue acquisition fully insured against all risks we face in our business. opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the Oil and gas exploration and production is speculative and involves a high availability of credit could materially adversely affect our ability to achieve degree of risk and hazards. In particular, our operations may be disrupted our planned growth and operating results. by risks and hazards that are beyond our control and that are common We are subject to complex laws common to the oil and natural gas industrial accidents, occupational safety and health hazards, technical failures, industry, which can have a material adverse effect on our business, labor disputes, community protests or blockades, unusual or unexpected financial condition and results of operations. geological formations, flooding, earthquakes and extended interruptions due among oil and gas companies, including environmental hazards, blowouts, to weather conditions, explosions and other accidents. For example, in The oil and natural gas industry is subject to extensive regulation and the first half of 2013 we experienced a well control incident at our Chercán 1 intervention by governments throughout the world, including extensive well in the Flamenco Block in Chile with no harm to employees or property. local, state and federal regulations, in such matters as the award of While we were able to bring that incident under control without injuries exploration and production interests, the imposition of specific exploration or environmental damage, there can be no assurance that we will not and drilling obligations, allocation of and restrictions on production, price experience similar or more serious incidents in the future, which could result controls, required divestments of assets and foreign currency controls, in damage to, or destruction of, wells or production facilities, personal and the development and nationalization, expropriation or cancellation of injury, environmental damage, business interruption, financial losses and contract rights. legal liability. We have been required in the past, and may be required in the future, While we believe that we maintain customary insurance coverage for to make significant expenditures to comply with governmental laws and companies engaged in similar operations, we are not fully insured against all regulations, including with respect to the following matters: • licenses, permits and other authorizations for drilling operations; • reports concerning operations; risks in our business. In addition, insurance that we do and may carry may contain significant exclusions from and limitations on coverage. We may elect not to obtain certain non-mandatory types of insurance if we believe that • compliance with environmental, health and safety laws and regulations; the cost of available insurance is excessive relative to the risks presented. • drafting and implementing emergency planning; The occurrence of a significant event or a series of events against which we • plugging and abandonment costs; and • taxation. Under these laws and regulations, we could be liable for, among other things, personal injury, property damage, environmental damage and other types of damage. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to are not fully insured and any losses or liabilities arising from uninsured or underinsured events could have a material adverse effect on our business, financial condition or results of operations. The development schedule of oil and natural gas projects is subject to cost overruns and delays. administrative, civil and criminal penalties. Moreover, these laws and Oil and natural gas projects may experience capital cost increases and regulations could change in ways that could substantially increase our costs. overruns due to, among other factors, the unavailability or high cost Any such liabilities, obligations, penalties, suspensions, terminations or of drilling rigs and other essential equipment, supplies, personnel and oil regulatory changes could have a material adverse effect on our business, field services. The cost to execute projects may not be properly established financial condition or results of operations. and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting In addition, the terms and conditions of the agreements under which and procurement costs. Development of projects may be materially our oil and gas interests are held generally reflect negotiations with adversely affected by one or more of the following factors: governmental authorities and can vary significantly. These agreements take • shortages of equipment, materials and labor; the form of special contracts, concessions, licenses, associations or other • fluctuations in the prices of construction materials; types of agreements. Any suspensions, terminations or regulatory changes • delays in delivery of equipment and materials; in respect of these special contracts, concessions, licenses, associations • our ability to close our pending Morona Block Acquisition. or other types of agreements could have a material adverse effect on our • labor disputes; business, financial condition or results of operations. • political events; GeoPark 20F 37 • title problems; greater number of properties and prospects than our financial or personnel • obtaining easements and rights of way; resources permit. Our competitors may also be able to offer better • blockades or embargoes; • litigation; compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition for capital • compliance with governmental laws and regulations, including available for investment in the oil and natural gas industry. As a result of each environmental, health and safety laws and regulations; of the aforementioned, we may not be able to compete successfully in the • adverse weather conditions; • unanticipated increases in costs; • natural disasters; • accidents; • transportation; • unforeseen engineering and drilling complications; • environmental or geological uncertainties; and • other unforeseen circumstances. future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel or raising additional capital, which could have a material adverse effect on our business, financial condition or results of operations. See “-Item 4. Information on the Company-B. Business overview-Our competition.” In Chile, we partner with and sell to, and may from time to time compete with, ENAP and, to a lesser extent, some companies with operations in Argentina mentioned below. In Colombia, we partner with and sell to, and Any of these events or other unanticipated events could give rise to delays may from time to time compete with, Ecopetrol, as well as with privately- in development and completion of our projects and cost overruns. owned companies such as Pacific Rubiales, Gran Tierra, Parex Resources Colombia Ltd. Sucursal, or Parex, and Canacol, among others. In Brazil, we For example, in 2013, the drilling and completion cost for the exploratory partner with and sell to, and may from time to time compete with, Petrobras, well Chilco x-1 in our Flamenco Block in Chile was originally estimated at privately-owned companies such as HRT, QGEP, Brasoil and some of the US$2.6 million, but the actual cost was approximately US$4.0 million, mainly Colombian companies mentioned above, which have entered into Brazil, due to mechanical issues during the drilling as it was the first well drilled among others. In Argentina, we compete for resources with YPF, as well as with a new drilling rig. with privately-owned companies such as Pan American Energy, Pluspetrol, Tecpetrol, Chevron, Wintershall, Total, Sinopec and others. In Peru, we Delays in the construction and commissioning of projects or other technical expect to partner with and expect to sell to, Petroperú and will compete for difficulties may result in future projected target dates for production resources with privately-owned companies such as Pluspetrol, Gran Tierra, being delayed or further capital expenditures being required. These projects Repsol, Graña y Montero, Hunt Oil, Olympic Oil & Gas, Savia, among others; may often require the use of new and advanced technologies, which can and with state-owned oil companies such as China National Petroleum be expensive to develop, purchase and implement and may not function Corporation (CNPC). as expected. Such uncertainties and operating risks associated with development projects could have a material adverse effect on our business, Our estimated oil and gas reserves are based on assumptions that may results of operations or financial condition. prove inaccurate. Competition in the oil and natural gas industry is intense, which makes it Our oil and gas reserves estimates in Brazil, Chile, Colombia, and Peru as difficult for us to acquire properties and prospects, market oil and natural of December 31, 2014 are based on the D&M Reserves Report. Although gas and secure trained personnel. classified as “proved reserves,” the reserves estimates set forth in the D&M Reserves Reports are based on certain assumptions that may prove We compete with the major oil and gas companies engaged in the inaccurate. D&M’s primary economic assumptions in estimates included exploration and production sector, including state-owned exploration and oil and gas sales prices determined according to SEC guidelines, future production companies that possess substantially greater financial and expenditures and other economic assumptions (including interests, royalties other resources than we do for researching and developing exploration and taxes) as provided by us. and production technologies and access to markets, equipment, labor and capital required to acquire, develop and operate our properties. We also In Chile, D&M’s estimates are based in part on the assumption that Methanex compete for the acquisition of licenses and properties in the countries in continues to commit to purchase Fell Block gas under the existing long-term which we operate. contract beyond 2017. In Brazil, D&M’s estimates are also based in part on the assumption that the gas compression facility for the Manatí Field that Our competitors may be able to pay more for productive oil and natural gas started in 2014 will be completed by 2015. properties and exploratory prospects and to evaluate, bid for and purchase a 38 GeoPark 20F In Peru, the estimates are formulated on a pro forma basis. We expect to inaccessible for any period of time, this could delay delivery of crude oil in close the pending Morona Block Acquisition in 2015. Chile and materially harm our business. For example, in January 2011, social and labor unrest resulted in the roads to the Gregorio Refinery being closed Oil and gas reserves engineering is a subjective process of estimating for two days, and we were unable to deliver crude oil to ENAP. accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers may differ materially from those set out herein. In the Tierra del Fuego Blocks, we will temporarily depend on the existence of Numerous assumptions and uncertainties are inherent in estimating continuous ferry service to be able to transport crude oil from the island of quantities of proved oil and gas reserves, including projecting future rates Tierra del Fuego to the mainland. Ferry service may be adversely affected by of production, timing and amounts of development expenditures and prices weather conditions, in particular by certain combinations of strong winds and of oil and gas, many of which are beyond our control. Results of drilling, tidal currents that may occur, which may adversely affect our ability to deliver testing and production after the date of the estimate may require revisions to the crude oil we produce in Tierra del Fuego. In the Fell Block, we depend be made. For example, if we are unable to sell our oil and gas to customers, on ENAP-owned gas pipelines to deliver the gas we produce to Methanex, the this may impact the estimate of our oil and gas reserves. Accordingly, reserves sole purchaser of the gas we produce. If ENAP’s pipelines were unavailable, estimates are often materially different from the quantities of oil and gas that this could have a materially adverse effect on our ability to deliver and sell our are ultimately recovered, and if such recovered quantities are substantially product to Methanex, which could have a material adverse effect on our gas lower that the initial reserves estimates, this could have a material adverse sales. In addition, gas production in some areas in the Tierra del Fuego Blocks impact on our business, financial condition and results of operations. and the Otway and Tranquilo Blocks could require us to build a new network Our inability to access needed equipment and infrastructure in a timely which could require us to make significant capital investments. manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas In Colombia, producers of crude oil have historically suffered from tanker of gas pipelines in order for us to be able to deliver our product to market, production. transportation logistics issues and limited storage capacity, which cause delays in delivery and transfer of title of crude oil. Such capacity Our ability to market our oil and natural gas production depends substantially issues in Colombia may require us to transport crude from our Colombian on the availability and capacity of processing facilities, oil tankers, operations via truck, which may increase the costs of those operations. transportation facilities (such as pipelines, crude oil unloading stations and Road infrastructure is limited in certain areas in which we operate, and trucks) and other necessary infrastructure, which may be owned and certain communities have used and may continue to use road blockages, operated by third parties. Our failure to obtain such facilities on acceptable which can sometimes interfere with our operations in these areas. For terms or on a timely basis could materially harm our business. We may be example, in December 2014, our Colombian production had been impacted required to shut down oil and gas wells because access to transportation or by approximately 5,000 bopd during the last 13 days of the year by a road processing facilities may be limited or unavailable when needed. If that blockage, which was restored to normal production levels by the beginning were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which of January 2015. could cause a material adverse effect on our business, financial condition While Brazil has a well-developed network of hydrocarbon pipelines, and results of operations. In addition, the shutting in of wells can lead to storage and loading facilities, we may not be able to access these facilities mechanical problems upon bringing the production back on line, potentially when needed. Pipeline facilities in Brazil are often full and seasonal capacity resulting in decreased production and increased remediation costs. The restrictions may occur, particularly in natural gas pipelines. Our failure exploitation and sale of oil and natural gas and liquids will also be subject to secure transportation or access to pipelines or other facilities once we to timely commercial processing and marketing of these products, commence operations in the concessions we were awarded in Brazil on which depends on the contracting, financing, building and operating of acceptable terms or on a timely basis could materially harm our business. infrastructure by third parties. In Chile, we transport the crude oil we produce in the Fell Block by truck to through the existing North Peruvian Pipeline, which has enough idle ENAP s processing, storage and selling facilities at the Gregorio Refinery. capacity to transport such future production. However, infrastructure As of the date of this Annual Report, ENAP purchases all of the crude oil we problems or social unrest affecting the pipeline operation may adversely produce in Chile. We rely upon the continued good condition, maintenance affect our production or revenues related to the Morona Block. In addition, and accessibility of the roads we use to deliver the crude oil we produce. as the Morona Block is located in a remote area of the tropical rainforest, If the condition of these roads were to deteriorate or if they were to become the development of the project involves that significant infrastructure has In Peru, future production in the Morona Bock is expected to be transported GeoPark 20F 39 to be built, as processing facilities, storages tanks and an approximately Additionally, offshore drilling generally requires more time and more 97 km pipeline from the site to the North Peruvian Pipeline. Also, as there advanced drilling technologies, involving a higher-risk of technological failure are no roads available in the surrounding area, logistics will be done by and usually higher drilling costs. Offshore projects often lack proximity to helicopters or barges during specific seasons of the year. existing oilfield service infrastructure, necessitating significant capital Our use of seismic data is subject to interpretation and may not accurately oil or gas of a commercial discovery, increasing both the financial and identify the presence of oil and natural gas. operational risk involved with these operations. Because of the lack and high cost of infrastructure, some offshore reserve discoveries may never be investment in flow line infrastructure before we can market the associated Even when properly used and interpreted, seismic data and visualization produced economically. techniques are tools only used to assist geoscientists in identifying subsurface structures as well as eventual hydrocarbon indicators, and do not enable the Further, because we are not the operator of our offshore fields, all of these interpreter to know whether hydrocarbons are, in fact, present in those risks may be heightened since they are outside of our control. We have a structures. In addition, the use of seismic and other advanced technologies 10% interest in the Manatí Field which limits our operating flexibility in requires greater pre-drilling expenditures than traditional drilling strategies, such offshore fields. See “-We are not, and may not be in the future, the and we could incur losses as a result of these expenditures. Because of these sole owner or operator of all of our licensed areas and do not, and may uncertainties associated with our use of seismic data, some of our drilling not in the future, hold all of the working interests in certain of our licensed activities may not be successful or economically viable, and our overall areas. Therefore, we may not be able to control the timing of exploration drilling success rate or our drilling success rate for activities in a particular or development efforts, associated costs, or the rate of production of any area could decline, which could have a material adverse effect on us. non-operated and, to an extent, any non-wholly-owned, assets.” Through our Brazilian operations, we face operational risks relating to Our pending acquisition of the Morona Block in Peru is subject to offshore drilling that we have not faced in the past. regulatory approvals. To date, we have operated solely as an onshore oil and gas exploration and In October 2014 we agreed to acquire from Petroperú a 75% working production company. However, our operations in the BCAM-40 Concession interest in the Morona Block in Northern Peru. We have been qualified as an in Brazil may include shallow-offshore drilling activity in two areas in the operator by Perupetro S.A. (“Perupetro”), the Peruvian hydrocarbons Camamu-Almada Basin, which we expect will continue to be operated by licensing agency. The closing of the acquisition is subject to the occurrence Petrobras. of certain conditions, including obtaining other governmental approvals. Failure to obtain such approvals before June 30, 2015 may result in Offshore operations are subject to a variety of operating risks and laws and termination of the agreement. The transaction is expected to close in 2015. regulations, including among other things, with respect to environmental, See “-Item 4. Information on the Company-B. Business overview-Significant health and safety matters, specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse Agreements-Peru- Morona Block Acquisition.” weather conditions. These conditions can cause substantial damage to We may suffer delays or incremental costs due to difficulties in negotiations facilities and interrupt production. As a result, we could incur substantial with landowners and local communities where our reserves are located. liabilities, compliance costs, fines or penalties that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, Access to the sites where we operate requires agreements (including, for or result in loss of equipment and properties. For example, the Manatí example, assessments, rights of way and access authorizations) with Field has been subject to administrative infraction notices, which have landowners and local communities. If we are unable to negotiate agreements resulted in fines against Petrobras in an aggregate amount of US$12.5 million, with landowners, we may have to go to court to obtain access to the sites all of which are pending a final decision of the Brazilian Institute for the of our operations, which may delay the progress of our operations at such Environment and Natural Renewable Resources (Instituto Brasileiro do sites. In Chile, for example, we have negotiated the necessary agreements for Meio-Ambiente e dos Recursos Naturais Renováveis), or IBAMA. Although many of our current operations in the Magallanes Basin. In the Tierra del the administrative fines were filed against Petrobras, as a party to the Fuego Blocks, although we have successfully negotiated access to our sites, concession agreement governing the Manatí Field, Rio das Contas may be any future disputes with landowners or court proceedings may delay our liable up to its participation interest of 10%. See “-Item 4. Information operations in Tierra del Fuego Blocks. In Brazil, in the event that social unrest on the Company-B. Business overview-Health, safety and environmental that occurred in 2013 continues or intensifies, this may lead to delays or matters-Other regulation of the oil and gas industry-Brazil.” damage relating to our ability to operate the assets we have acquired or may acquire in our Brazil Acquisitions. 40 GeoPark 20F In Colombia, although we have agreements with many landowners and are we have identified under these contracts and agreements yield discoveries, in negotiations with others, we expect our costs to increase following current we may face delays in drilling these prospects or be required to relinquish and future negotiations regarding access to our blocks, as the economic these prospects. The costs to maintain or operate the CEOPs, E&P Contracts expectations of landowners have generally increased, which may delay and concession agreements over such areas may fluctuate and may increase access to existing or future sites. In addition, the expectations and demands significantly, and we may not be able to meet our commitments under of local communities on oil and gas companies operating in Colombia have such contracts and agreements on commercially reasonable terms or at all, increased in the wake of recent changes to the royalty regime in Colombia. which may force us to forfeit our interests in such areas. For example, on As a result, local communities have demanded that oil and gas companies January 17, 2013, we voluntarily and formally announced to the Chilean invest in remediating and improving public access roads, compensate them Ministry of Energy our decision not to proceed with the second exploration for any damages related to use of such roads and, more generally, invest period and to terminate the exploration phase under the Tranquilo Block in infrastructure that was previously paid for with public funds. Due to these CEOP, and subsequently relinquished all areas of the Tranquilo Block, except circumstances, oil and gas companies in Colombia, including us, are now for an area of 92,417 gross acres, where we declared four hydrocarbons dealing with increasing difficulties resulting from instances of social unrest, discoveries. Additionally, on April 10, 2013, we voluntarily and formally temporary road blockages and conflicts with landowners. For example, announced to the Chilean Ministry of Energy our decision not to proceed in December 2014, production from certain fields in the Llanos 34 Block was with the second exploratory period and to terminate the exploration phase affected by a road blockage resulting in our reduction of production for a under the Otway Block CEOP, and subsequently relinquished all areas of period of thirteen days that was returned to normal in early January 2015. the Otway Block, except for two areas totaling 49,421 gross acres in There can be no assurance that disputes with landowners and local on the Company-B. Business overview-Our operations-Operations in communities will not delay our operations or that any agreements we reach Argentina-Del Mosquito Block” See “-Item 4. Information on the Company-B. with such landowners and local communities in the future will not require Business overview-Our operations-Operations in Chile-Otway and which we have declared hydrocarbons discoveries. See “-Item 4. Information us to incur additional costs, thereby materially adversely affecting our Tranquilo Blocks.” business, financial condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected In Peru, the rights to explore and produce hydrocarbons are granted government to restrict our access to the sites of our operations, which may through a License Contract signed with Perupetro, a governmental entity. have a material adverse effect on our operations at such sites. As GeoPark agreed to acquire a 75% interest in the Morona Block from Petroperú, we expect to be a partner to the Morona Block License Contract In Peru, the Morona Block is located in land inhabited by native communities. in 2015. This contract includes the obligation for GeoPark and Petroperú, Land use agreements will have to be signed with the communities and our partner in the block, to build the facilities required to produce the social support programs are expected to be implemented by GeoPark. In the hydrocarbons discovered in the block. The scope and schedule of such Morona Block, approximately seventy-five indigenous communities, which development will depend on us and Petroperú. The License Contract could fall into twelve distinct community structures, have been identified. Despite indigenous community support for hydrocarbons activities since the mid- be terminated by Perupetro if the development obligations included in such agreement are not fulfilled. In addition, there is also an exploratory nineties, similar projects in the Peruvian rainforest have faced social conflicts commitment consisting of the drilling of one exploratory well every two and works delays due to community claims. and a half years. Failure to fulfill the exploratory commitment will lead to acreage relinquishment materially affecting the project. Under the terms of some of our various CEOPs, E&P Contracts and concession agreements, we are obligated to drill wells, declare Moreover, we have entered into a Joint Investment Agreement with any discoveries and file periodic reports in order to retain our rights and Petroperú by which we are obliged to bear 100% of capital cost required to establish development areas. Failure to meet these obligations may carry out long test to existing wells Situche Central 2X and Situche Central result in the loss of our interests in the undeveloped parts of our blocks 3X. Failure to do so will result in the loss of our participating interest in or concession areas. the License Contract of the Morona Block, and subject us to possible damage claims from Petroperú. In order to protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, For additional details regarding the status of our operations with respect unless we make and declare discoveries within certain time periods specified to our various special contracts and concession agreements, see “-Item 4. in our various CEOPs, E&P Contracts and concession agreements, our interests Information on the Company-B. Business overview- Our operations.” in the undeveloped parts of our license areas may lapse. Should the prospects GeoPark 20F 41 A significant amount of our reserves and production have been pursuant to the Fell Block CEOP, under which we are in the exploitation derived from our operations in three blocks, the Llanos 34 in Colombia, phase, Chile may terminate the CEOP if (i) we stop performing any of the Fell Block in Chile and the BCAM-40 Concession in Brazil. the substantial obligations assumed under the Fell Block CEOP without cause and do not cure such nonperformance pursuant to the terms of the For the year ended December 31, 2014, the Llanos 34 Block contained 49% of concession, following notice of breach or (ii) our oil activities are interrupted our net proved reserves and generated 42% of our production, the Fell Block for more than three years due to force majeure circumstances (as defined contained 26% of our net proved reserves and generated 30% of our total in the Fell Block CEOP). If the Fell Block CEOP is terminated in the exploitation production and the BCAM-40 Concession contained 16% of our net proved phase, we will have to transfer to Chile, free of charge, any productive wells reserves and generated 17% of our production. While our recent expansion and related facilities, provided that such transfer does not interfere with into Brazil, Argentina and Colombia with new exploratory blocks incorporated our abandonment obligations and excluding certain pipelines and other in our portfolio in 2014 (and our expected future expansion into Peru) mean assets. See “-Item 4. Information on the Company-B. Business overview- that these blocks are expected to be less significant component of our overall Significant agreements-Chile-CEOPs- Fell Block CEOP.” If the CEOP is business than it has been in the past, we nonetheless expect that such blocks terminated early due to a breach of our obligations, we may not be entitled will continue to be responsible for a significant portion of our reserves and to compensation. Additionally, our CEOPs for the Tierra del Fuego Blocks, production. Any government intervention, impairment or disruption of our which are in the exploration phase, may be subject to early termination production due to factors outside of our control or any other material adverse during this phase under circumstances including (i) a failure by us to comply event in our operations in such blocks would have a material adverse effect with minimum work commitments at the termination of any exploration on our business, financial condition and results of operations. period, (ii) a failure to communicate our intention to proceed with the next exploration period 30 days prior to its termination, (iii) a failure to provide Our contracts in obtaining rights to explore and develop oil and natural gas the Chilean Ministry of Energy requisite performance bonds, (iv) a voluntary reserves are subject to contractual expiration dates and operating relinquishment by us of all areas under the CEOP, (v) a failure by us to conditions, and our CEOPs, E&P Contracts and concession agreements are meet the requirements to enter into the exploitation phase upon the subject to early termination in certain circumstances. termination of the exploration phase, and (vi) a permanent suspension by us of all operations in the CEOP area or our declaration of bankruptcy. If the Under certain of the CEOPs, E&P Contracts and concession agreements to Tierra del Fuego Block CEOPs are terminated within the exploration phase, which we are or may in the future become parties, we are or may become we are released from all obligations under the CEOPs, except for obligations subject to guarantees to perform our commitments and/or to make payment regarding the abandonment of fields, if any. See “-Item 4. Information for other obligations, and we may not be able to obtain financing for all such on the Company-B. Business overview-Significant agreements-Chile-CEOPs.” obligations as they arise. If such obligations are not complied with when There can be no assurance that the early termination of any of our CEOPs due, in addition to any other remedies that may be available to other parties, would not have a material adverse effect on us. this could result in cancelation of our CEOPs, E&P Contracts and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2014, the aggregate outstanding amount of this potential liability for In addition, according to the Chilean Constitution, Chile is entitled to expropriate our rights in our CEOPs for reasons of public interest. Although guarantees was approximately US$69.8 million, mainly relating to guarantees Chile would be required to indemnify us for such expropriation, there of our minimum work program for the VIM 3 Block in Colombia, our minimum can be no assurance that any such indemnification will be paid in a timely work program for Tierra del Fuego Blocks in Chile and, to a significantly manner or in an amount sufficient to cover the harm to our business caused lesser extent, minimum work programs for our other Colombian operations, by such expropriation. the ten Brazilian concession areas and the new blocks in Argentina. In Colombia, our E&P Contracts may be subject to early termination for a Additionally, certain of the CEOPs, E&P Contracts and concession agreements breach by the parties, a default declaration, application of any of the to which we are or may in the future become a party are subject to set contracts’ unilateral termination clauses or pursuant to termination clauses expiration dates. Although we may want to extend some of these contracts mandated by Colombian law. Anticipated termination declared by the ANH beyond their original expiration dates, there is no assurance that we results in the immediate enforcement of monetary guaranties against us can do so on terms that are acceptable to us or at all, although some CEOPs and may result in an action for damages by the ANH and/or a restriction contain provisions enabling exploration extensions. on our ability to engage in contracts with the Colombian government during In particular, in Chile, our CEOPs provide for early termination by Chile in Business overview- Significant agreements-Colombia-E&P Contracts.” certain circumstances, depending upon the phase of the CEOP. For example, a certain period of time. See “-Item 4. Information on the Company-B. 42 GeoPark 20F In Brazil, concession agreements generally may be renewed, at the ANP’s Supply Agreement, which expires on April 30, 2017. Sales to Methanex discretion, for an additional period, provided that a renewal request is made represented 6% of our consolidated revenues for the year ended December at least 12 months prior to the termination of the concession agreement 31, 2014. Methanex also buys gas from ENAP and a consortium that Methanex and there has not been a breach of the terms of the concession agreement. has formed with ENAP. While our contract with Methanex requires it to We expect that all our concession agreements will provide for early purchase the entirety of our production of natural gas from the Fell Block, termination in the event of: (i) government expropriation for reasons of and requires us to sell to Methanex all of our natural gas production from Fell public interest; (ii) revocation of the concession pursuant to the terms of the Block, subject to minor exceptions, if Methanex were to decrease or cease concession agreement; or (iii) failure by us or our partners to fulfill all of its purchase of gas from us, this would have a material adverse effect on our our respective obligations under the concession agreement (subject to a cure revenues derived from the sale of gas. In addition, there can be no assurance period). Administrative or monetary sanctions may also be applicable, that we will be able to extend or renew our contract with Methanex past as determined by the ANP, which shall be imposed based on applicable law April 30, 2017, which could have a material adverse effect on our business, and regulations. In the event of early termination of a concession agreement, financial condition and results of operations. the compensation to which we are entitled may not be sufficient to compensate us for the full value of our assets. Moreover, in the event of early Methanex has two methanol producing facilities at its Cabo Negro termination of any concession agreement due to failure to fulfill obligations production facility, near the city of Punta Arenas in southern Chile. However, thereunder, we may be subject to fines and/or other penalties. after Argentine natural gas producers cut off exports to Chile in 2007, Methanex had to stop production at all but one of these facilities, and began In Peru, License Contracts for hydrocarbon exploitation are in force and to rely on local suppliers of natural gas, including ENAP, for its operations. will remain in effect for 30 years. This term is non-renewable. With regards to Since 2009, however, the amount of natural gas that ENAP has been able to the Morona Block, currently one-third of the contract term has already provide to Methanex has been decreasing, as ENAP has given priority to elapsed, and twenty years remain. Nevertheless, since November 27, 2013, providing natural gas to the city of Punta Arenas in the Magallanes region. the License Contract related to the Morona Block is under force majeure. Although we sell all the natural gas we produce in the Fell Block to Methanex, During a force majeure period contract terms are suspended (including the and supplied approximately 50% of all the natural gas consumed by term time) as long as the party to the contract is fulfilling certain obligations Methanex before the idling of its plant in May 2014, we alone cannot supply pertaining to obtaining environmental permits, as is currently the case Methanex with all the natural gas it requires for its operations. with the Morona Block. The term of the agreement will be extended by the same amount of time it has been suspended by a force majeure event. The plant was idled due to an anticipated insufficient supply of natural gas. The concession year expiration is related to approval of environmental The supply of natural gas decreased during the winter months of 2014 impact assessment (EIA) study for project development. The expiration of due to the increase in seasonal gas demand from the city of Punta Arenas, concession will occur twenty years after EIA approval. We expect the EIA to to which gas producers, including GeoPark, gave priority, delivering gas to be approved in approximately in December 2016. the city through Methanex which re-sold our gas to ENAP. Methanex The License Contract is also subject to early termination in case of breach continued to purchase from us the volume of gas we produced during the idling, and we signed an amendment to the agreement, pursuant to of contractual obligations by GeoPark. In such an event, all the existing which Methanex pays us a premium over the current gas price for deliveries facilities and wells located in the block will be transferred, without charge, to exceeding certain volumes of gas, since the Methanex plant’s startup, Perupetro, and abandonment plans will have to be carried out by GeoPark which occurred on September 11, 2014. See “-Item 4. Information on the for remediation and restoration of any polluted area in the block, and for de- Company-B. Business overview-Marketing and delivery commitments-Chile.” commissioning the facilities that are no longer required for block’s operations. Methanex made investments aimed at lowering its plant’s minimum gas requirements during the idling, so that the plant is currently able to function Early termination or nonrenewal of any CEOP, E&P Contract or concession with 21.2 mcfpd of gas. agreement could have a material adverse effect on our business, financial situation or results of operations. However, there can be no assurance that Methanex will continue to purchase the gas from us or that its efforts to reduce the risk of future shutdowns We sell almost all of our natural gas in Chile to a single customer, who has will be successful, which could have a material adverse effect on our gas in the past temporarily idled its principal facility. revenues. Additionally, there can be no assurance that Methanex will For the year ended December 31, 2014, almost all of our natural gas sales in our gas production. If Methanex were to cease purchasing from us, there can Chile were made to Methanex under a long-term contract, the Methanex Gas be no assurance that we would be able to sell our gas production to other have sufficient supplies of gas to operate its plant and continue to purchase GeoPark 20F 43 parties or on similar terms, which could have a material adverse effect on our As of December 31, 2014, we are not the operator of the Llanos 17, Llanos 32 business, financial condition and results of operations. and Jagu(cid:0) eyes 3432 A Blocks in Colombia, which represented 3% of our total production as of December 31, 2014. In Chile we are not the sole owner of the We may not be able to meet delivery requirements under the agreement Tranquilo, Isla Norte, Campanario and Flamenco blocks. In Colombia we are for the sale of our natural gas in Chile. not the sole owner of the Llanos 34, CPO-4, Abanico and Cerrito blocks. Under the Methanex Gas Supply Agreement, Methanex has committed to In Brazil, we are not the operator of the BCAM-40 Concession, which purchasing, and we have committed to selling, all of the gas that we represented approximately 14% of our total production for the year ended produce in the Fell Block (subject to certain exceptions, including reasonable December 31, 2014. quantities required to maintain our operations and quantities that we might be required to pay in kind to Chile), with a minimum volume commitment In Peru we will not be the sole owner of the Morona Block, as we are which is defined by us on an annual basis. The agreement contains monthly expected to assume a 75% working interest of the Morona Block, DOP obligations, which require us to deliver in a given month the minimum with Petroperú retaining a 25% working interest. Petroperú will also have gas committed for that month or pay a deficiency penalty to Methanex, the right to increase its working interest in the Block by up to 50%, subject with a threshold of 90% of the committed quantities of gas. The agreement to us recovering our investments in the Block through certain agreed also contains monthly TOP obligations, which apply when our committed terms. See “-Item 4. Information on the Company-B. Business overview- volume for a given month exceeds 35.3 mcfpd, and require Methanex to take Our operations-Operations in Peru-Morona Block.” in such month the minimum gas volume committed for such period or face higher TOP obligations in later months, with a threshold of 90% of the In addition, the terms of the joint venture agreements or association committed quantities. These DOP and TOP obligations are subject to make- agreements governing our other partners’ interests in almost all of the blocks up provisions without penalty, for any delivery or off-take deficiencies that are not wholly-owned or operated by us require that certain actions accrued, in the three months following the month where delivery or off-take be approved by supermajority vote. The terms of our other current or future requirements were not met. license or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability On April 1, 2014, the Company and Methanex executed a fifth amendment to exercise influence over operations or prospects in the blocks operated to the Gas Supply Agreement, valid until April 30, 2015, which extended by our partners, or in blocks that are not wholly-owned or operated by us. A the fourth amendment conditions until May 18, 2015, and defined breach of contractual obligations by our partners who are the operators of new conditions for the winter 2014 period (May 2014 to September 2014) such blocks could eventually affect our rights in exploration and production and the post-winter period (October 2014 to April 2015). For the post-winter contracts in our blocks in Colombia. Our dependence on our partners could period the Company committed to deliveries over 400,000 SCM/d. The prevent us from realizing our target returns for those discoveries or prospects. fifth amendment also waived the DOP and TOP thresholds for both parties, replacing them with reasonable efforts to take and deliver, and giving GeoPark’s gas first priority over any third party supplies to Methanex. Moreover, as we are not the sole owner or operator of all of our properties, we may not be able to control the timing of exploration or development Though the fifth amendment waived the DOP and TOP thresholds for be able to carry out our key business strategies of minimizing the cycle time both parties, such clauses or new clauses introduced in further amendments between discovery and initial production at such properties. The success may apply for periods beyond the ones covered in the above mentioned and timing of exploration and development activities operated by our amendment. For example, in 2012, we failed to meet this adjusted volume for partners will depend on a number of factors that will be largely outside of activities or the amount of capital expenditures and may therefore not each of the months of April through December of 2012, such that we accrued US$1.7 million in DOP payments owed to Methanex under the Methanex our control, including: • the timing and amount of capital expenditures; Gas Supply Agreement, all of which had been paid as of September 30, 2013. • the operator’s expertise and financial resources; • approval of other block partners in drilling wells; We are not, and may not be in the future, the sole owner or operator of • the scheduling, pre-design, planning, design and approvals of activities and all of our licensed areas and do not, and may not in the future, hold all of processes; the working interests in certain of our licensed areas. Therefore, we may • selection of technology; and not be able to control the timing of exploration or development efforts, • the rate of production of reserves, if any. associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly-owned, assets. 44 GeoPark 20F This limited ability to exercise control over the operations on some of our Colombia to declare dividends only after allowing for retentions of cash license areas may cause a material adverse effect on our financial condition for approved work programs and budgets and capital adequacy requirements and results of operations. of GeoPark Colombia, working capital requirements, banking covenants associated with any loan entered into by GeoPark Colombia or our other LGI, our strategic partner in Chile and Colombia, may not consent to Colombian subsidiaries and operational requirements. Our inability to obtain our taking certain actions or may eventually decide to sell its interest in LGI’s consent or a delay by LGI in granting its consent may restrict or delay our Chilean and Colombian operations to a third party. the ability of GeoPark Chile, GeoPark TdF or GeoPark Colombia to take certain actions, which may have an adverse effect on our operations in such We have a strategic partnership with LGI, which has a 20% equity interest in countries and on our business, financial condition and results of operations. GeoPark Chile, a 14% direct equity interest in GeoPark TdF (31.2% taking into account direct and indirect participation through GeoPark Chile) and a Acquisitions that we have completed and any future acquisitions, strategic 20% equity interest in GeoPark Colombia, through its equity interest in investments, partnerships or alliances could be difficult to integrate and/or GeoPark Colombia Cooperatie. Our shareholders’ agreements with LGI in each identify, could divert the attention of key management personnel, disrupt of Chile and Colombia provides that we have a right of first offer if LGI our business, dilute stockholder value and adversely affect our financial decides to sell any of its interest in GeoPark Chile or GeoPark Colombia. There results, including impairment of goodwill and other intangible assets. can be no assurance, however, that we will have the funds to purchase LGI’s interest in Chile and/or Colombia and that LGI will not decide to sell its shares One of our principal business strategies includes acquisitions of properties, to a third party whose interests may not be aligned with ours. prospects, reserves and leaseholds and other strategic transactions, In addition, our shareholders’ agreements with LGI in Chile and Colombia successful acquisition and integration of producing properties, including contain provisions that require GeoPark Chile and GeoPark Colombia to our acquisitions of Winchester, Luna and Cuerva in Colombia, our Brazil obtain LGI’s consent before undertaking certain actions. For example, under acquisitions and pending Morona Block Acquisition, requires an assessment including in jurisdictions in which we do not currently operate. The the terms of the shareholders’ agreement with LGI in Colombia, LGI must approve GeoPark Colombia’s annual budget and work programs and of several factors, including: • recoverable reserves; mechanisms for funding any such budget or program, the entering into any • future oil and natural gas prices; borrowings other than those provided in an approved budget or incurred • development and operating costs; and in the ordinary course of business to finance working capital needs, the • potential environmental and other liabilities. granting of any guarantee or indemnity to secure liabilities of parties other than those of our Colombian subsidiaries and disposing of any material assets The accuracy of these assessments is inherently uncertain. In connection other than those provided for in an approved budget and work program. with these assessments, we perform a review of the subject properties that Similarly, in Chile, pursuant to the terms of our shareholders’ agreements we believe to be generally consistent with industry practices. Our review with LGI, LGI’s consent is required in order for GeoPark Chile or GeoPark TdF, as applicable, to be able to take certain actions, including: making any and the review of advisors and independent reserves engineers will not reveal all existing or potential problems nor will it permit us or them to become decision to terminate or permanently or indefinitely suspend operations in sufficiently familiar with the properties to fully assess their deficiencies and or surrender our blocks in Chile (other than as required under the terms of potential recoverable reserves. Inspections may not always be performed on the relevant CEOP for such blocks); selling our blocks in Chile to our affiliates; every well, and environmental conditions are not necessarily observable making any change to the dividend, voting or other rights that would give even when an inspection is undertaken. We, advisors or independent reserves preference to or discriminate against the shareholders of these companies; engineers may apply different assumptions when assessing the same field. entering into certain related party transactions; and creating a security Even when problems are identified, the seller may be unwilling or unable interest over our blocks in Chile (other than in connection with a financing to provide effective contractual protection against all or part of the problems. that benefits our Chilean subsidiaries). We often are not entitled to contractual indemnification for environmental Additionally, pursuant to our agreements with LGI in Chile, we and LGI have circumstances in which we have contractual indemnification rights for pre- agreed to vote our common shares or otherwise cause GeoPark Chile or closing liabilities, it remains possible that the seller will not be able to fulfill GeoPark TdF, as the case may be, to declare dividends only after allowing its contractual obligations. There can be no assurance that problems related for retentions of cash to meet anticipated future investments, costs and to the assets or management of the companies and operations we have obligations, and pursuant to our agreement with LGI in Colombia, we and acquired, such as in Colombia or Brazil, or other companies or operations we LGI have agreed to vote our common shares or otherwise cause GeoPark may acquire in future, will not arise in future, and these problems could liabilities and acquire properties on an “as is” basis. Even in those GeoPark 20F 45 have a material adverse effect on our business, financial condition and results 13, 2013. Due to the injunction and a decision from the Board of the ANP, of operations. GeoPark Brazil could not proceed to execute the concession agreement, and cannot do so until the injunction is either lifted or clarified as to what Significant acquisitions and other strategic transactions may involve other conditions and which type of conventional drilling activities may be carried risks, including: out by GeoPark Brazil. According to the terms of the Court’s injunction, • diversion of our management’s attention to evaluating, negotiating and the ANP will first need to take certain actions, such as conducting studies integrating significant acquisitions and strategic transactions; that prove that drilling unconventional resources will not contaminate • challenge and cost of integrating acquired operations, information the dams and aquifers in the region. On February 21, 2014, GeoPark Brazil management and other technology systems and business cultures with those requested that the board of the ANP suspend the execution of the concession of ours while carrying on our ongoing business; • contingencies and liabilities that could not be or were not identified during the due diligence process, including with respect to possible deficiencies in agreement (which entails delivery of the financial guarantee and performance guarantee and payment of the signing bonus) for six months with a possible extension of an additional six months, or until a firm court decision the internal controls of the acquired operations; and is reached that does not prevent GeoPark Brazil from entering into the • challenge of attracting and retaining personnel associated with acquired concession agreement. operations. If we fail to realize the benefits we anticipate from an acquisition, our results proceedings related to the award of the concession of Block PN-T-597 to of operations may be adversely affected. GeoPark Brazil were suspended. On April 16, 2014, the ANP’s Board enacted a resolution stating that all It is also possible that we may not identify suitable acquisition targets Due to similar law suits with the same types of claims filed in the states of or strategic investment, partnership or alliance candidates. Our inability to Paraná and Bahia, where the Court decision was to carry out conventional identify suitable acquisition targets, strategic investments, partners or drilling activities, we expect that such decisions may impact the law suit alliances, or our inability to complete such transactions, may negatively affect filed against us related to the Block PN-T-597, and also the ANP’s decision our competitiveness and growth opportunities. Moreover, if we fail to to suspend the process for not signing the concession agreement. properly evaluate acquisitions, alliances or investments, we may not achieve the anticipated benefits of any such transaction and we may incur costs in However, there can be no assurance that we will be able to extend the excess of what we anticipate. deadlines associated with the entry into the Concession Contract or enter into the concession agreement. See “-Item 8-Financial Information-A. Future acquisitions financed with our own cash could deplete the cash and Consolidated statements and other financial information-Legal working capital available to adequately fund our operations. We may also proceedings.” finance future transactions through debt financing, the issuance of our equity securities, existing cash, cash equivalents or investments, or a combination of the foregoing. Acquisitions financed with the issuance of our equity The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated securities could be dilutive, which could affect the market price of our stock. oil and natural gas reserves. Acquisitions financed with debt could require us to dedicate a substantial portion of our cash flow to principal and interest payments and could subject You should not assume that the present value of future net revenues from us to restrictive covenants. our proved reserves is the current market value of our estimated oil and natural gas reserves. For the year ended December 31, 2014, we have based The PN-T-597 concession in Brazil is subject to an injunction and may the estimated discounted future net revenues from our proved reserves not close. on the 12 month unweighted arithmetic average of the first-day-of-the- month price for the preceding 12 months. Actual future net revenues from In Brazil, GeoPark Brazil is currently a party to a legal proceeding related our oil and natural gas properties will be affected by factors such as: to entry into the concession agreement of exploratory Block PN-T-597 that • actual prices we receive for oil and natural gas; the ANP initially awarded to GeoPark Brazil in the 12th oil and gas bidding • actual cost of development and production expenditures; round held in November 2013. As a result of a class action filed by the Federal • the amount and timing of actual production; and Prosecutor’s Office, an injunction was issued by a Brazilian Federal Court • changes in governmental regulations, taxation or the taxation invariability against the ANP, the Federal Government and GeoPark Brazil on December provisions in our CEOPs. 46 GeoPark 20F The timing of both our production and our incurrence of expenses in Furthermore, some of our customers may be highly leveraged, and, in any connection with the development and production of oil and natural gas event, are subject to their own operating expenses. Therefore, the risk we face properties will affect the timing and amount of actual future net revenues in doing business with these customers may increase. Other customers may from proved reserves, and thus their actual value. In addition, the 10% also be subject to regulatory changes, which could increase the risk of discount factor we use when calculating discounted future net revenues defaulting on their obligations to us. Financial problems experienced by our may not be the most appropriate discount factor based on interest rates customers could result in the impairment of our assets, a decrease in our in effect from time to time and risks associated with us or the oil and natural operating cash flows and may also reduce or curtail our customers’ future use gas industry in general. of our products and services, which may have an adverse effect on our revenues and may lead to a reduction in reserves. The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently We may not have the capital to develop our unconventional oil and anticipate. Therefore, our proved undeveloped reserves ultimately gas resources. may not be developed or produced. We have identified opportunities for analyzing the potential of As of December 31, 2014, only approximately 32% of our net proved unconventional oil and gas resources in some of our blocks and concessions. reserves have been developed (or 33% including the Morona Block in Peru). Our ability to develop this potential depends on a number of factors, Development of our undeveloped reserves may take longer and require including the availability of capital, seasonal conditions, regulatory approvals, higher levels of capital expenditures than we currently anticipate. negotiation of agreements with third parties, commodity prices, costs, Additionally, delays in the development of our reserves or increases in access to and availability of equipment, services and personnel and drilling costs to drill and develop such reserves will reduce the standardized results. In addition, as we have no previous experience in drilling and measure value of our estimated proved undeveloped reserves and future exploiting unconventional oil and gas resources, the drilling and exploitation net revenues estimated for such reserves, and may result in some projects of such unconventional oil and gas resources depends on our ability to becoming uneconomic, causing the quantities associated with these acquire the necessary technology, to hire personnel and other support uneconomic projects to no longer be classified as reserves. This was due needed for extraction or to obtain financing and venture partners to develop to the uneconomic status of the reserves, given the proximity to the such activities. Because of these uncertainties, we cannot give any assurance end of the concessions for these blocks, which does not allow for future as to the timing of these activities, or that they will ultimately result in the capital investment in the blocks. There can be no assurance that we realization of proved reserves or meet our expectations for success. will not experience similar delays or increases in costs to drill and develop our reserves in the future, which could result in further reclassifications Our operations are subject to operating hazards, including extreme of our reserves. weather events, which could expose us to potentially significant losses. We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely Our operations are subject to potential operating hazards, extreme weather conditions and risks inherent to drilling activities, seismic registration, affect our cash flow and results of operations. exploration, production, development and transportation and storage of crude oil, such as explosions, fires, car and truck accidents, floods, labor Our customers may experience financial problems that could have a disputes, social unrest, community protests or blockades, guerilla attacks, significant negative effect on their creditworthiness. Severe financial security breaches, pipeline ruptures and spills and mechanical failure of problems encountered by our customers could limit our ability to equipment at our or third-party facilities. Any of these events could have a collect amounts owed to us, or to enforce the performance of obligations material adverse effect on our exploration and production operations, owed to us under contractual arrangements. or disrupt transportation or other process-related services provided by our The combination of declining cash flows as a result of declines in commodity prices, a reduction in borrowing basis under reserves-based credit We are highly dependent on certain members of our management and facilities and the lack of availability of debt or equity financing may result technical team, including our geologists and geophysicists, and on in a significant reduction of our customers’ liquidity and limit their ability to our ability to hire and retain new qualified personnel. make payments or perform on their obligations to us. third-party contractors. The ability, expertise, judgment and discretion of our management and our technical and engineering teams are key in discovering and developing oil GeoPark 20F 47 and natural gas resources. Our performance and success are dependent to a in a timely manner or at all (such as due to opposition from partners, large extent upon key members of our management and exploration team, community or environmental interest groups, governmental delays or any and their loss or departure would be detrimental to our future success. In other reasons) or if we face additional requirements due to changes in addition, our ability to manage our anticipated growth depends on our ability applicable laws and regulations, our operations could be adversely affected, to recruit and retain qualified personnel. Our ability to retain our employees impeded, or terminated, which could have a material adverse effect on our is influenced by the economic environment and the remote locations of business, financial condition or results of operations. Some environmental our exploration blocks, which may enhance competition for human resources licenses related to operation of the Manatí Field production system and where we conduct our activities, thereby increasing our turnover rate. natural gas pipeline have expired. However, the operator submitted timely a There is strong ongoing competition in our industry to hire employees in request for renewal of those licenses and as such this operation is not in operational, technical and other areas, and the supply of qualified employees default as long as the regulator does not state its final position on the renewal. is limited in the regions where we operate and throughout Latin America generally. The loss of any of our executive officers or other key employees We, as the owner, shareholder or the operator of certain of our past, current of our technical team or our inability to hire and retain new qualified and future discoveries and prospects, could be held liable for some or all personnel could have a material adverse effect on us. 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, We and our operations are subject to numerous environmental, health predecessors or other operators. To the extent we do not address these and safety laws and regulations which may result in material liabilities costs and liabilities or if we do not otherwise satisfy our obligations, our and costs. operations could be suspended, terminated or otherwise adversely affected. We have also contracted with and intend to continue to hire third parties We and our operations are subject to various international, foreign, federal, to perform services related to our operations. There is a risk that we may state and local environmental, health and safety laws and regulations contract with third parties with unsatisfactory environmental, health and governing, among other things, the emission and discharge of pollutants safety records or that our contractors may be unwilling or unable to cover any into the ground, air or water; the generation, storage, handling, use, losses associated with their acts and omissions. Accordingly, we could be transportation and disposal of regulated materials; and human health and held liable for all costs and liabilities arising out of the acts or omissions of our safety. Our operations are also subject to certain environmental risks that are contractors, which could have a material adverse effect on our results of inherent in the oil and gas industry and which may arise unexpectedly and operations and financial condition. result in material adverse effects on our business, financial condition and results of operations. Breach of environmental laws, as well as impacts on Releases of regulated substances may occur and can be significant. Under natural resources and unauthorized use of such resources, could result certain environmental laws and regulations applicable to us in the countries in environmental administrative investigations and/or lead to the termination in which we operate, we could be held responsible for all of the costs of our concessions and contracts. Other potential consequences include relating to any contamination at our past and current facilities and at any fines and/or criminal or civil environmental actions. For instance, non- governmental organizations seeking to preserve the environment may bring third-party waste disposal sites used by us or on our behalf. Pollution resulting from waste disposal, emissions and other operational practices actions against us or other oil and gas companies in order to, among might require us to remediate contamination, or retrofit facilities, at other things, halt our activities in any of the countries in which we operate substantial cost. We also could be held liable for any and all consequences or require us to pay fines. Additionally, in Colombia, recent rulings arising out of human exposure to such substances or for other damage have provided that environmental licenses are administrative acts subject resulting from the release of hazardous substances to the environment, to class actions that could eventually result in their cancellation, with property or to natural resources, or affecting endangered species or sensitive potential adverse impacts on our E&P Contracts. environmental areas. Environmental laws and regulations also require that wells be plugged and sites be abandoned and reclaimed to the satisfaction We are required to obtain environmental permits from governmental of the relevant regulatory authorities. We are currently required to, and authorities for our operations, including drilling permits for our wells. We in the future may need to, plug and abandon sites in certain blocks in each of have not been and may not be at all times in complete compliance with the countries in which we operate, which could result in substantial costs. 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 In addition, we expect continued and increasing attention to climate change requirements, we could be fined or otherwise sanctioned by regulators, issues. Various countries and regions have agreed to regulate emissions including through the revocation of our permits or the suspension or of greenhouse gases including methane (a primary component of natural termination of our operations. If we fail to obtain, maintain or renew permits gas) and carbon dioxide (a byproduct of oil and natural gas combustion). 48 GeoPark 20F The regulation of greenhouse gases and the physical impacts of climate million, which includes interest payments under the Notes due 2020 change in the areas in which we, our customers and the end-users and the credit facility with Itaú BBA International plc. See “Item 5. Operating of our products operate could adversely impact our operations and the and Financial Review and Prospects-B. Liquidity and Capital Resources- demand for our products. Indebtedness.” We are also restricted from entering into borrowing arrangements in some circumstances such as in Colombia where LGI must Environmental, health and safety laws and regulations are complex and approve GeoPark Colombia’s borrowing arrangements, see “Item 4- change frequently, and have tended to become increasingly stringent over Information about the Company-History,” for more information. time. Our costs of complying with current and future climate change, environmental, health and safety laws, the actions or omissions of our Our substantial indebtedness could: partners and third-party contractors and our liabilities arising from releases • make it more difficult for us to satisfy our obligations with respect to of, or exposure to, regulated substances may adversely affect our results our indebtedness, and any failure to comply with the obligations of of operations and financial condition. See “-Item 4. Information on the any of our debt instruments, including restrictive covenants and borrowing Company-B. Business overview-Health, safety and environmental matters” conditions, could result in an event of default under the agreements and “-Item 4. Information on the Company-B. Business overview- Industry and regulatory framework.” governing our indebtedness; • require us to dedicate a substantial portion of our cash flow from operations to the payments on our indebtedness, thereby reducing the availability Legislation and regulatory initiatives relating to hydraulic fracturing of our cash flow to fund acquisitions, working capital, capital expenditures and other drilling activities for unconventional oil and gas resources could and other general corporate purposes; increase the future costs of doing business, cause delays or impede our • place us at a competitive disadvantage compared to certain of our plans, and materially adversely affect our operations. competitors that have less debt; • limit our ability to borrow additional funds; Hydraulic fracturing of unconventional oil and gas resources is a process • in the case of our secured indebtedness, lose assets securing such that involves injecting water, sand, and small volumes of chemicals into the indebtedness upon the exercise of security interests in connection with wellbore to fracture the hydrocarbon-bearing rock thousands of feet below a default; the surface to facilitate a higher flow of hydrocarbons into the wellbore. • make us more vulnerable to downturns in our business or the economy; We are contemplating such use of hydraulic fracturing in the production of and oil and natural gas from certain reservoirs, especially shale formations. We • limit our flexibility in planning for, or reacting to, changes in our operations currently are not aware of any proposals in Chile, Colombia, Brazil, or or business and the industry in which we operate. Argentina to regulate hydraulic fracturing beyond the regulations already in place. However, various initiatives in other countries with substantial shale Our Notes due 2020 include a covenant restricting dividend payments. For gas resources have been or may be proposed or implemented to, among a description, see “-Item 5. Operating and Financial Review and Prospects-B. other things, regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict Liquidity and Capital Resources-Indebtedness-Notes due 2020.” which additives may be used, or implement temporary or permanent bans As a result of these restrictive covenants, we are limited in the manner in on hydraulic fracturing. If any of the countries in which we operate adopts which we conduct our business, and we may be unable to engage in similar laws or regulations, which is something we cannot predict right favorable business activities or finance future operations or capital needs. now, such adoption could significantly increase the cost of, impede or cause At current prices, absent certain customary exceptions, we do not anticipate delays in the implementation of any plans to use hydraulic fracturing for achieving an EBITDA (as defined in the indenture governing our notes due unconventional oil and gas resources. 2020) during fiscal year 2015 that would be sufficient enough to allow us to incur additional indebtedness, other than certain categories and small Our substantial indebtedness could adversely affect our financial health baskets of permitted debt, as specified in the indenture. Failure to comply and our ability to raise additional capital, and prevent us from fulfilling with the restrictive covenants included in our Notes due 2020 would not our obligations under our existing agreements and borrowing of trigger an event of default. additional funds. As of December 31, 2014, we had US$369.6 million of total indebtedness refinance or enter into new debt agreements which could intensify the risks Similar restrictions could apply to us and our subsidiaries when we outstanding on a consolidated basis, which is 100% secured. As of December described above. 31, 2014, our annual debt service obligation was approximately US$25.3 GeoPark 20F 49 Our business could be negatively impacted by security threats, including in laws and policies governing operations of foreign-based companies, cybersecurity threats as well as other disasters, and related disruptions. expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, the obtaining of various approvals Our business processes depend on the availability, capacity, reliability from regulators, foreign exchange restrictions, price controls, currency and security of our information technology infrastructure and our ability fluctuations, royalty increases and other risks arising out of foreign to expand and continually update this infrastructure in response to our governmental sovereignty, as well as to risks of loss due to civil strife, acts of changing needs. It is critical to our business that our facilities and war and community-based actions, such as protests or blockades, guerilla infrastructure remain secure. Although we have implemented internal activities, terrorism, acts of sabotage, territorial disputes and insurrection. control procedures to assure the security of our data, we cannot guarantee In addition, we are subject both to uncertainties in the application of the tax that these measures will be sufficient for this purpose. The ability of the laws in the countries in which we operate and to possible changes in such information technology function to support our business in the event of tax laws (or the application thereof), each of which could result in an increase a security breach or a disaster such as fire or flood and our ability to recover in our tax liabilities. These risks are higher in developing countries, such as key systems and information from unexpected interruptions cannot be those in which we conduct our activities. fully tested and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of a breach. In the The main economic risks we face and may face in the future because of our event of a breach, key information and systems may be unavailable for a number of days leading to an inability to conduct our business or perform operations in the countries in which we operate include the following: • difficulties incorporating movements in international prices of crude oil some business processes in a timely manner. We have implemented and exchange rates into domestic prices; strategies to mitigate the impact from these types of events. • the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s, Peru’s Our employees have been and will continue to be targeted by parties using will impact negatively on capital controls, and result in a deterioration of the fraudulent “spam” and “phishing” emails to misappropriate information business climate; or to introduce viruses or other malware through “trojan horse” programs • inflation, exchange rate movements (including devaluations), exchange to our computers. These emails appear to be legitimate emails sent by us but control policies (including restrictions on remittance of dividends), price or Brazil’s relations with multilateral credit institutions, such as the IMF, direct recipients to fake websites operated by the sender of the email or instability and fluctuations in interest rates; request that the recipient send a password or other confidential information • liquidity of domestic capital and lending markets; through email or download malware. Despite our efforts to mitigate “spoof” • tax policies; and and “phishing” emails through education, “spoof” and “phishing” activities • the possibility that we may become subject to restrictions on repatriation of remain a serious problem that may damage our information technology earnings from the countries in which we operate in the future. infrastructure. Risks relating to the countries in which we operate 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, Our operations may be adversely affected by political and economic tribal conflicts and governmental policies that may: disrupt our operations; circumstances in the countries in which we operate and in which we may require us to incur greater costs for security; restrict the movement of operate in the future. funds or limit repatriation of profits; lead to U.S. government or international sanctions; limit access to markets for periods of time; or influence the All of our current operations are located in South America. For the year ended market’s perception of the risk associated with investments in these December 31, 2014, our operations in Brazil, Chile and Colombia represented countries. Some countries in the geographic areas where we operate have 14 %, 31 % and 55 %, respectively, of our total production, with our Argentine experienced, and may experience in the future, political instability, and operations representing less than 1% of our total production. If local, regional losses caused by these disruptions may not be covered by insurance. or worldwide economic trends adversely affect the economy of any of the Consequently, our exploration, development and production activities may countries in which we have investments or operations, our financial condition be substantially affected by factors which could have a material adverse effect and results from operations could be adversely affected. on our results of operations and financial condition. Argentina’s National election for President and Vice-President will take place in October 2015, and Oil and natural gas exploration, development and production activities are other local and federal elections will also take place in 2015. We cannot subject to political and economic uncertainties (including but not limited guarantee that current programs and policies that apply to the oil and gas to changes in energy policies or the personnel administering them), changes industry will remain in effect. 50 GeoPark 20F Our operations may also be adversely affected by laws and policies of the provides us with a long-term off-take contract with Petrobras, the Brazilian jurisdictions, including Bermuda, Chile, Colombia, Brazil, Peru, Argentina, state-owned company that covers approximately 74% of net proved gas the Netherlands and other jurisdictions in which we do business, that affect reserves in the Manatí Field. If we, the respective host governments and the foreign trade and taxation, and by uncertainties in the application of, national oil companies are not able to cooperate with one another, it possible changes to (or to the application of) tax laws in these jurisdictions. could have an adverse impact on our business, operations and prospects. Changes in any of these laws or policies or the implementation thereof, and uncertainty over potential changes in policy or regulations affecting Oil and natural gas companies in Chile, Colombia, Brazil, Peru and any of the factors mentioned above or other factors in the future may Argentina do not own any of the oil and natural gas reserves in such increase the volatility of domestic securities markets and securities issued countries. abroad by companies operating in these countries, which could materially and adversely affect our financial position, results of operations and cash Under Chilean, Colombian, Brazilian, Peruvian and Argentine law, all onshore flows. Furthermore, we may be subject to the exclusive jurisdiction of courts and offshore hydrocarbon resources in these countries are owned by the outside the United States or may not be successful in subjecting non-U.S. respective sovereign. Although we are the operator of the majority of the persons to the jurisdiction of courts in the United States, which could blocks and concessions in which we have a working and/or economic interest adversely affect the outcome of such dispute. and generally have the power to make decisions as how to market the The ongoing “Lava Jato” investigation regarding corruption at and Argentine governments have full authority to determine the rights, royalties with Petróleo Brasileiro S.A., or Petrobras, may hinder the growth of the or compensation to be paid by or to private investors for the exploration or Brazilian economy and could have an adverse effect on our business. production of any hydrocarbon reserves located in their respective countries. hydrocarbons we produce, the Chilean, Colombian, Brazilian, Peruvian and Petrobras and certain other Brazilian companies active in the energy and Under the Chilean Constitution, the state is the exclusive owner of all mineral infrastructure sectors are facing investigations by the Securities Commission and fossil substances, including hydrocarbons, regardless of who owns the of Brazil (Comissão de Valores Mobiliários), the U.S. Securities and land on which the reserves are located. The exploration and exploitation Exchange Commission, the Brazilian Federal Police and the Brazilian Federal of hydrocarbons may be carried out by the state, companies owned by state Prosecutor’s Office, in connection with corruption allegations, or the or private persons through administrative concessions granted by the “Lava Jato” investigations. Depending on the duration and outcome of such President of Chile by Supreme Decree or by CEOPs executed by the Minister investigations, the companies involved may face downgrades from rating of Energy. Hydrocarbon exploration and exploitation activities are regulated agencies, funding restrictions and a reduction in their revenues. Given the by the Chilean Ministry of Energy. In Chile, a participant is granted rights relatively significant weight of the companies cited in the investigation, to explore and exploit certain assets under a CEOP. Although the government this could have an adverse effect on Brazil’s growth prospects and could have cannot unilaterally modify or terminate the rights granted in the CEOP a protracted effect on the oil and gas industry. Negative effects on a number once it is signed, if a participant fails to complete certain obligations under of companies may also impact the level of investments in infrastructure in Brazil which may lead to lower economic growth in the near to medium a CEOP, such participant may lose the right to exploit certain areas or may be required to return all or a portion of the awarded areas back to Chile. term. Persistently poor macroeconomic conditions resulting from, among other things, the Lava Jato investigations and their consequences could have In Colombia, oil and natural gas companies have acquired the exclusive a material adverse effect on us as Brazil is one of the markets we operate in. right to explore, develop and produce reserves discovered within certain We depend on maintaining good relations with the respective host Colombian government through the ANH or, prior to 2004, entered into with governments and national oil companies in each of our countries of Ecopetrol. However, a concessionaire owns only the oil and natural gas concession areas, pursuant to concession agreements awarded by the operation. that it extracts under the concession agreements to which it is a party. If the Colombian government were to restrict or prevent concessionaires, including The success of our business and the effective operation of the fields in us, from exploiting these oil and natural gas reserves, or otherwise interfere each of our countries of operation depend upon continued good relations with our exploration through regulations with respect to restrictions on and cooperation with applicable governmental authorities and agencies, future exploration and production, price controls, export controls, foreign including national oil companies such as ENAP, Ecopetrol and Petrobras. exchange controls, income taxes, expropriation of property, environmental For instance, for the year ended December 31, 2014, 100% of our crude oil legislation or health and safety, this could have a material adverse effect and condensate sales in Chile were made to ENAP, the Chilean state-owned on our business, financial condition and results of operations. oil company. In addition, our recent Rio das Contas acquisition in Brazil GeoPark 20F 51 Additionally, we are dependent on receipt of Colombian government and Mines. The qualification has already been granted by Perupetro, and the approvals or permits to develop the concessions we hold in Colombia. There Supreme Decree is expected to be issued in 2015. can be no assurance that future political conditions in Colombia will not result in the Colombian government adopting different policies with respect Under the License Contract of Morona Block, GeoPark and Petroperú to foreign development and ownership of oil, environmental protection, (GeoPark’s anticipated partner in the block) will have the exclusive right to health and safety or labor relations. This may affect our ability to undertake perform exploration and production activities in such block, and will pay exploration and development activities in respect of present and future royalties for the hydrocarbons produced in this area. The ownership of the properties, as well as our ability to raise funds to further such activities. Any hydrocarbons produced in the Morona Block will belong to GeoPark in delays in receiving Colombian government approvals, permits or no accordance with its participation interest in the block. objection certificates may delay our operations or may affect the status of our contractual arrangements or our ability to meet contractual obligations. The exploration and production activities of GeoPark in the Morona Block will largely be shaped by the provisions included in the License Contract, Pursuant to Article 20 of the Brazilian Constitution and Article 3 of Law and without such contract it is not possible to carry out any oil and gas No. 9,478, dated as of August 6, 1997, as amended, or the Brazilian Petroleum activity in the Morona Block. Law, oil, natural gas and hydrocarbon reserves located within the Brazilian territory, which encompasses onshore and offshore reserves, as well as In Argentina, jurisdiction over oil and gas activities is now largely vested in deposits in the Brazilian continental shelf, territorial waters and exclusive the same provincial states who own the relevant underground oil and gas economic zone, are considered assets of the Brazilian government. Therefore, resources. The Federal Executive Branch is still empowered to design the concessionaire owns only the oil and natural gas that it produces and rule federal energy policy and to rule on domestic inter-jurisdictional under the concession agreements. Oil and natural gas companies in Brazil and international oil and gas transportation concessions and has, for example, acquire the exclusive right to explore, develop and produce reserves imposed measures controlling oil and gas investments in the provincial discovered within certain concession areas pursuant to concession states. Private companies must obtain exploration permits or exploitation agreements awarded by the Brazilian government. However, if the Brazilian concessions from the provincial states or otherwise enter into certain government were to restrict or prevent concessionaires, including us, types of joint venture or association agreements with provincial state-owned from exploiting these oil and natural gas reserves, or interfere in the sale oil and gas companies in order to undertake exploration and production or transfer of the production, our ability to generate income would be activities onshore, and must enter into certain types of joint venture or materially adversely affected, which would have a material adverse effect association agreements with the federally-owned oil and gas company, on our business, financial condition and results of operations. ENARSA, to undertake these activities offshore. Additionally, whereas until 2012, exploration permit and exploitation concession holders had Companies in the Brazilian oil and natural gas industry also rely primarily on the right to freely dispose of and market up to 70% of the production they the public auction process regulated by the ANP to acquire rights to explore generated, on July 28th, 2012, the publication of Presidential Decree oil and natural gas reserves. While the ANP may offer concessions in certain basins in future bidding rounds, there is a risk that future bidding rounds 1277/2012 abrogated this right. As of December 31, 2014, our production in Argentina represented less than 1% of our total production, though may not take place or that they do not include desirable locations, since they recent regulations affecting the oil and gas industry in Argentina may have are conducted by and under the Brazilian government’s discretion, which an adverse impact on our business, operations and prospects in Argentina. could have a material adverse effect on our business, expected results of operations and financial condition. Oil and gas operators are subject to extensive regulation in the countries In Peru, oil and gas exploration and production activities are conducted in which we operate. under license contracts granted by the Peruvian government. GeoPark has In Chile, rights to exploration and exploitation of a particular area are acquired a participation interest in the License Contract of Morona Block, established in a CEOP. According to article 19, No 24 of the Chilean and the effectiveness of such acquisition is subject to the approval by the Constitution, the President of Chile has the power to determine the terms Peruvian government. The governmental approval includes the qualification and conditions for the granting of a particular CEOP. In addition, the of GeoPark by Perupetro, in order to determine if it fulfills all the requirements CEOP is subject to extensive supervision by the government through the needed to develop exploration and production activities in the Morona Chilean Ministry of Energy. The President of Chile may also decide to Block, as well as and the enactment of a Supreme Decree issued by the terminate a CEOP early, though with compensation to the counterparty, and Peruvian Ministry of Economy and Finance and the Peruvian Ministry Energy only if the relevant area is located within an area declared relevant for national security reasons. 52 GeoPark 20F Although the government of Chile cannot unilaterally modify the rights of operations or our being subjected to administrative, civil and criminal granted in the CEOP once it is signed, exploration and exploitation are penalties, which could have a material adverse effect on our financial nonetheless subject to significant government regulations, such as condition and expected results of operations. We expect to also operate in a regulations concerning the environment, tort liability, health and safety consortium in some of our concessions, which, under the Brazilian Petroleum and labor, all of which have an impact on our business and operations. Law, establishes joint and strict liability among consortium members. If Changes in laws and regulations could have an adverse effect on the costs the operator does not maintain the appropriate licenses, the consortium may and timing of our operations. For example, in November 2012, the suffer administrative penalties, including fines of R$10 to R$500 million. government approved new regulations governing the abandonment of mines and oilfield operations that would require us to obtain prior approval In addition, the local content policy, which is a contractual requirement in a for new oil wells and could also require us to post a bond in connection Brazilian concession agreements, has become a significant issue for oil with the abandonment or closure of an oil well. and natural gas companies operating in Brazil given the penalties related with breaches thereof. The local content requirement will also apply to the The Colombian hydrocarbons industry is subject to extensive regulation production sharing contract regime. See “-Item 4. Information on the and supervision by the government in matters such as the environment, Company-B. Business overview-Our operations-Operations in Brazil.” tort liability, health and safety, labor, the award of exploration and production contracts by the ANH, the imposition of specific drilling and In Peru, the hydrocarbons industry is also subject to extensive regulation exploration obligations, taxation, foreign currency controls, price controls, and supervision by the government in matters such as: environment, capital expenditures and required divestments. Existing Colombian health and safety, labor, imposition of specific development and exploration regulation applies to virtually all aspects of our concessions or E&P Contracts obligations, taxation, and tort liability. There are many supervisors and in Colombia. The terms and conditions of the agreements with the ANH regulators, for example: a) Perupetro, the state-owned company that generally reflect negotiations with the ANH and other Colombian promotes, negotiates, signs, and supervises exploration and production governmental authorities, and may vary by fields, basins and hydrocarbons contracts; b) The Ministry of Energy and Mines, which is the central and discovered. governing body for the Energy, Hydrocarbons and Mining Sector, and a part of the Executive Branch; c) The Bureau of Environmental Evaluation and We are required, as are all oil companies undertaking exploratory and Control – OEFA, which is the supervisory body that regulates, enforces and production activities in Colombia, to pay a percentage of our expected oversees the activities undertaken related to environmental hydrocarbon production to the Colombian government as royalties. The Colombian issues; d) The Supervisory Body of Private Investment in Energy and Mines – government has modified the royalty program for oil and natural gas OSINERGMIN, which is the regulatory, supervisory body that regulates production several times in the last 20 years, as it has modified the regime the activities undertaken by legal entities and individuals in the hydrocarbons regulating new contracts entered into with the Colombian government. sectors; e) The General Bureau of Environmental Health – DIGESA, which The royalty regime for contracts being entered into today for conventional is the technical-regulatory body for aspects related to basic sanitation, oil is tied to a scale ring-fenced by field starting at 8% for production of up to 5,000 mbopd and increases up to 25% for production above 600,000 occupational health, hygienic food, zoonosis and environmental protection; f) the Ministry of Agriculture, which is the entity that promotes the development mbopd. Royalties for natural gas production of onshore blocks where of organized agrarian producers in productive chains; and g) The Ministry of our assets are located, range between 8% and 25%. Furthermore, production Labor and Employment Promotion – MTPE, which is the body governing labor of unconventional resources discovered as of May 19, 2012 is subject to in Peru, responsible for enforcement of legislation for labor matters. royalties equivalent to 60% of the royalties applicable to conventional oil. In Brazil, the oil and natural gas industry is subject to extensive regulation General Hydrocarbons Law (Law 26,221) (“General Hydrocarbons Law”), and and intervention by the Brazilian government in such matters as the award of several regulations have been enacted in order to develop the provisions exploration and production interests, taxation and foreign currency controls. included therein. There are specific regulations for exploration and Ultimately, those regulations may also address restrictions on production, production, transport, commercialization, storage, refining, distribution by The main provisions regarding oil and gas activities are included in the price controls, mandatory divestments of assets and nationalization, pipelines, etc. expropriation or cancellation of contractual rights. Under these laws and regulations, there is potential liability for personal foresee that the signing of an oil and gas agreement implies the guarantee injury, property damage and other types of damages. Failure to comply with that the tax regime in effect at the date of signature will not be changed these laws and regulations also may result in the suspension or termination during the life of the contract. This is intended to preserve the economy of Furthermore, the General Hydrocarbons Law and the related tax regulations GeoPark 20F 53 the contract so that no further tax costs are created for the contractors. The decline in our expected net sales or net income could lead to a deterioration signing of an agreement for the exploration or exploitation of a block freezes in our financial condition. the tax regime in force at the date that the contract is signed for the entire life of the contract. Taxes covered by this provision are the taxes in which the In Argentina, since 2001, the Argentine government has imposed and responsibility rests on the contractor as a taxpayer. expanded upon exchange controls and restrictions on the transfer of U.S. dollars outside of Argentina, which substantially limit the ability of companies The Argentine hydrocarbons industry is also extensively regulated both by to retain foreign currency or make payments abroad. These and other federal and provincial state regulations in matters including the award of measures have led the implied AR$/US$ exchange rate as reflected in the exploration permits and exploitation concessions, investment, royalty, canon, quotations for certain Argentine securities that trade in foreign markets price controls, export restrictions and domestic market supply obligations. to differ substantially from the official foreign exchange rate in Argentina. If the The terms of our exploitation concessions are embodied in Decrees and Argentine government decides once again to tighten the restrictions on the Administrative Decisions issued by the Federal Executive Power and transfer of funds, we may be unable to make payments related to the import of incorporate statutory rights and obligations provided under the General products and services, which could have a material adverse effect on us. Hydrocarbons Law. The federal government is further empowered to design and implement federal energy policy and to rule on domestic inter- Additionally, in May 2012, the Argentine government expropriated 51% jurisdictional and international oil and gas transportation concessions, and of YPF’s capital stock owned by Repsol YPF of Spain, and 51% of the capital has used these powers to establish export restrictions and duties, induce stock of Repsol YPF Gas owned by Repsol Butano. private companies to enter into price stability agreements with the government or otherwise impose price control regulations or create incentive There can be no assurance that future economic, social and political programs to promote increased production. Jurisdictional controversies developments in the countries in which we operate currently or in the future, among the federal government and the provincial states are not uncommon. which are out of our control, may impair our business, financial condition and results of operations. Significant expenditures may be required to ensure our compliance with governmental regulations related to, among other things, licenses for Our operations may be affected by tax reforms in the countries in which drilling operations, environmental matters, drilling bonds, reports concerning we operate and in which we may operate in the future. operations, the spacing of wells, unitization of oil and natural gas accumulations, local content policy and taxation. Our operations may be affected by changes in tax laws in the countries in which we operate and in which we may operate in the future. In 2014 Governmental actions in the countries in which we operate and in which Colombian and Chilean governments introduced tax reforms. For example, we may operate in the future may adversely affect our business, financial in the fourth quarter 2014, the Colombian government approved tax condition and results of operations. Our business, financial condition and results of operations may be adversely legislation increasing the rate of tax applicable to ordinary income from 34% in 2014 to 39% for 2015, 40% for 2016, 42% for 2017 and 43% for 2018. In the same legislation, the Colombian government also instituted a new affected by actions taken by the Chilean, Colombian, Brazilian, Peruvian or “wealth tax” payable on the net equity of our Colombia business units at Argentine governments concerning the economy, including actions aimed at a rate of 1.15% for 2015, 1% for 2016 and 0.4% for 2017. (See Note 15 to our targeting inflation, interest rates, oil and gas price controls, foreign exchange Financial Statements included in this Annual Report). controls and taxes. In Brazil, the Brazilian government frequently implements changes to tax and Brazil has in the past periodically experienced extremely high rates of social security regimes that may affect us and our customers. These changes inflation. As measured by the National Consumer Price Index (Índice Nacional include changes in prevailing tax and contribution rates and, occasionally, de Preços ao Consumidor Amplo), Brazil had annual rates of inflation of 6.5% enactment of temporary taxes, the proceeds of which are earmarked for in 2011, 5.8% in 2012, 5.9% in 2013 and 6.4 % in 2014. Brazil may experience designated governmental purposes. Some of these changes in tax laws may high levels of inflation in the future. Periods of higher inflation may slow result in increases in our tax payments, which could materially adversely the rate of growth of the Brazilian economy. Although the long-term off-take affect our profitability and increase the prices of our products and services, contract covering gas production in the Manatí Field is indexed to inflation, restrict our ability to do business in our existing and target markets and cause inflation is likely to increase some of our costs and expenses, and, as a result, our results of operations to suffer. There can be no assurance that we will be may reduce our profit margins and net income. Inflationary pressures could able to maintain our projected cash flow and profitability following any also lead to counter-inflationary prices that may harm our business. Any increase in taxes applicable to us and to our operations. 54 GeoPark 20F Colombia has experienced and continues to experience internal security implications under Argentine law with respect to our incorporation in issues that have had or could have a negative effect on the Colombian Bermuda, which may subject our Argentine subsidiaries to higher tax rates. economy. Risks related to our common shares Colombia has experienced internal security issues, primarily due to the activities of guerrillas, including the Revolutionary Armed Forces of Colombia An active, liquid and orderly trading market for our common shares may (Fuerzas Armadas Revolucionarias de Colombia), or the FARC, paramilitary not develop and the price of our stock may be volatile, which could limit groups and drug cartels. In the past, guerrillas have targeted the crude oil your ability to sell our common shares. pipelines, including the Oleoducto Transandino, Caño Limón-Coveñas and Ocensa pipelines, and other related infrastructure disrupting the activities of Our common shares began to trade on the New York Stock Exchange on certain oil and natural gas companies. On several occasions guerilla attacks February 7, 2014, and as a result have a limited trading history. We cannot have resulted in unscheduled shut-downs of the transportation systems in predict the extent to which investor interest in our company will maintain an order to repair damaged sections and undertake clean-up activities. These active trading market on the NYSE, or how liquid that market will be in the activities, their possible escalation and the effects associated with them future. have had and may have in the future a negative impact on the Colombian economy or on our business, which may affect our employees or assets. In the The market price of our common shares may be volatile and may be context of the political instability, allegations have been made against members of the Colombian Congress and against government officials for influenced by many factors, some of which are beyond our control, including: • our operating and financial performance and identified potential drilling possible ties with guerilla groups. This situation may have a negative impact locations, including reserve estimates; on the credibility of the Colombian government, which could in turn have a • quarterly variations in the rate of growth of our financial indicators, such as negative impact on the Colombian economy or on our business in the future. net income per common share, net income and revenues; • changes in revenue or earnings estimates or publication of reports by The Colombian government commenced peace talks with the FARC in August equity research analysts; 2012. Our business, financial condition and results of operations could be • fluctuations in the price of oil or gas; adversely affected by rapidly changing economic or social conditions, • speculation in the press or investment community; including the Colombian government’s response to current peace • sales of our common shares by us or our shareholders, or the perception negotiations which may result in legislation that increases our tax burden or that such sales may occur; that of other Colombian companies. Tensions with neighboring countries • involvement in litigation; may affect the Colombian economy and, consequently, our results of • changes in personnel; operations and financial condition. • announcements by the company; In addition, from time to time, community protests and blockades may arise near our operations in Colombia, which could adversely affect our business, to our performance. • variations in our quarterly operating results; financial condition or results of operations. • volatility in our industry, the industries of our customers and the global • domestic and international economic, legal and regulatory factors unrelated securities markets; Our operations may be adversely affected by political and economic • changes in our dividend policy; circumstances in Argentina. • risks relating to our business and industry, including those discussed above; • strategic actions by us or our competitors; Some of our current operations and management offices are located in • actual or expected changes in our growth rates or our competitors’ growth Argentina. If local political or economic trends adversely affect the Argentine rates; economy, our financial condition and results from operations could be • investor perception of us, the industry in which we operate, the investment adversely affected. In particular, we face risks in Argentina related to the opportunity associated with our common shares and our future performance; following: restrictions on Argentina’s energy supplies and an inadequate • adverse media reports about us or our directors and officers; governmental response to such restrictions, which could negatively affect • addition or departure of our executive officers; Argentina’s economic activity; social and political tensions and the • change in coverage of our company by securities analysts; governmental response to such tensions; requirements of the Federal General • trading volume of our common shares; Environmental Law, which requires persons who carry out activities that are • future issuances of our common shares or other securities; potentially hazardous to the environment to obtain insurance; and tax • terrorist acts; GeoPark 20F 55 • the release or expiration of transfer restrictions on our outstanding common Additionally, we may not be able to fully control the operations and the assets shares. of our joint ventures and we may not be able to make major decisions or take timely actions with respect to our joint ventures unless our joint venture 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 future, cash dividends on our common shares, and, consequently, your with LGI in Chile and Colombia that limit the amount of dividends that can be only opportunity to achieve a return on your investment is if the price of declared or returned to us, certain aspects related to the management of our our stock appreciates. Chilean and Colombian businesses, the incurrence of indebtedness, liens and our ability to sell certain assets. See “-Risks relating to our business-LGI, We have never paid, and do not intend to pay in the foreseeable future, cash our strategic partner in Chile and Colombia, may sell its interest in our dividends on our common shares. Any decision to pay dividends in the future, Chilean and Colombian operations to a third party or may not consent to our and the amount of any distributions, is at the discretion of our board of taking certain actions.” We may, in the future, enter into other joint venture directors and our shareholders, and will depend on many factors, such as our agreements imposing additional restrictions on our ability to pay dividends. results of operations, financial condition, cash requirements, prospects and other factors. Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price We are also subject to Bermuda legal constraints that may affect our ability of our common shares to decline. to pay dividends on our common shares and make other payments. Under the Bermuda Companies Act, we may not declare or pay a dividend if there We may issue additional common shares or convertible securities in the future, are reasonable grounds for believing that we are, or would after the payment for example, to finance potential acquisitions of assets, which we intend to be, unable to pay our liabilities as they become due or that the realizable continue to pursue. Sales of substantial amounts of our common shares in the value of our assets would thereafter be less than our liabilities. We are also public market, or the perception that these sales may occur, could cause the subject to contractual restrictions under certain of our indebtedness. market price of our common shares to decline. This could also impair our ability We are a holding company dependent upon dividends from our memorandum of association, we are authorized to issue up to 5,171,949,000 subsidiaries, which may be limited by law and by contract from making common shares, of which 57,790,533 common shares were outstanding as of distributions to us, which would affect our financial condition, including December 31, 2014. We cannot predict the size of future issuances of our the ability to pay dividends on the common shares. common shares or the effect, if any, that future sales and issuances of shares to raise additional capital through the sale of our equity securities. Under our would have on the market price of our common shares. As a holding company, our only material assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal Provisions of the Notes due 2020 could discourage an acquisition of us by source of revenues and cash flow is distributions from our subsidiaries. Thus, a third party. our ability to pay dividends on the common shares will be contingent upon the financial condition of our subsidiaries. Our subsidiaries are and will be Certain provisions of the Notes due 2020 could make it more difficult or separate legal entities, and although they may be wholly-owned or controlled more expensive for a third party to acquire us, or may even prevent a third by us, they have no obligation to make any funds available to us, whether party from acquiring us. For example, upon the occurrence of a fundamental in the form of loans, dividends, distributions or otherwise. The ability of change, holders of the Notes due 2020 will have the right, at their option, our subsidiaries to distribute cash to us is also subject to, among other things, to require us to repurchase all of their notes at a purchase price equal to restrictions that are contained in our and our subsidiaries’ financing 101% of the principal amount thereof plus any accrued and unpaid interest (including our Notes due 2020 and GeoPark Brazil’s loan to finance Rio das (including any additional amounts, if any) to the date of purchase. By Contas) and joint venture agreements (principally our agreements with discouraging an acquisition of us by a third party, these provisions could have LGI), availability of sufficient funds in such subsidiaries and applicable state the effect of depriving the holders of our common shares of an opportunity laws and regulatory restrictions. Claims of creditors of our subsidiaries to sell their common shares at a premium over prevailing market prices. generally will have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent the ability Variations in interest rates and exchange rate on our current and/or of our subsidiaries to distribute dividends or other payments to us could be future financing arrangements may result in significant increases in our limited in any way, our business, financial condition and results of operations, borrowing costs. as well as our ability to pay dividends on the common shares, could be materially adversely affected. 56 GeoPark 20F As of December 31, 2014, a part (19%) of our total debt is sensitive to changes events, we are not required to file quarterly reports on Form 10-Q or provide in interest rates. At December 31, 2014, the outstanding long-term borrowing current reports on Form 8 K disclosing significant events within four days affected by variable rates amounted to US$ 68,540,000, representing 19% of their occurrence and our quarterly or current reports may contain less of total long-term borrowings, which was composed by the loan from Itaú Bank information than required under U.S. filings. In addition, we are exempt from that has a floating interest rate based on LIBOR (the “Rio das Contas Credit the Section 14 proxy rules, and proxy statements that we distribute will Facility”). For more information, see “Item 4-Marketing and Delivery not be subject to review by the SEC. Our exemption from Section 16 rules Commitments-Brazil,” and Note 3 in our Financial Statements. Consequently, regarding sales of common shares by insiders means that you will have variations in interest rates could result in significant changes in the amount less data in this regard than shareholders of U.S. companies that are subject required to cover our debt service obligations and our interest expense. to the Exchange Act. As a result, you may not have all the data that you are accustomed to having when making investment decisions. For example, our In addition, interest and principal amounts payable pursuant to debt obligations officers, directors and principal shareholders are exempt from the reporting denominated in or indexed to U.S. dollars are subject to variations in the foreign and “short-swing” profit recovery provisions of Section 16 of the Exchange currency exchange rates that could result in a significant increase in the amount Act and the rules thereunder with respect to their purchases and sales of our of the interest and principal payments in respect of such debt obligations. common shares. The periodic disclosure required of foreign private issuers Certain shareholders have substantial control over us and could limit your therefore be less publicly available information about us than is regularly ability to influence the outcome of key transactions, including a change published by or about U.S. public companies. See “-Item 10. Additional of control. Information-H. Documents on display.” is more limited than that required of domestic U.S. issuers and there may Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief As a foreign private issuer, we will be exempt from complying with certain Executive Officer, Mr. Juan Cristóbal Pavez, director and Mr. Steven J. corporate governance requirements of the NYSE applicable to a U.S. issuer, Quamme, control approximately 48% of our outstanding common shares as including the requirement that a majority of our board of directors consist of the date of this annual report, holding the shares either directly or through of independent directors. As the corporate governance standards applicable privately held funds which they control. As a result, these shareholders, to us are different than those applicable to domestic U.S. issuers, you may if acting together, would be able to influence or control matters requiring not have the same protections afforded under U.S. law and the NYSE rules as approval by our shareholders, including the election of directors and the shareholders of companies that do not have such exemptions. approval of amalgamations, mergers or other extraordinary transactions. They may also have interests that differ from yours and may vote in a way We are an “emerging growth company,” and we cannot be certain if the with which you disagree and which may be adverse to your interests. reduced disclosure requirements applicable to emerging growth companies The concentration of ownership may have the effect of delaying, preventing will make our common shares less attractive to investors. or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might ultimately affect the market We are an “emerging growth company,” as defined in the JOBS Act, and for as long as we continue to be an “emerging growth company” we may choose price of our common shares. See “Item 7. Major Shareholders and Related to take advantage of certain exemptions from various reporting requirements Party Transactions-A. Major shareholders” for a more detailed description that are applicable to other public companies that are not “emerging growth of our share ownership. companies,” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes As a foreign private issuer, we are subject to different U.S. securities laws Oxley Act. We cannot predict if investors will find our common shares less and NYSE governance standards than domestic U.S. issuers. This may attractive because we will rely on these exemptions. If some investors find our afford less protection to holders of our common shares, and you may not common shares less attractive as a result, there may be a less active trading receive corporate and company information and disclosure that you market for our common shares and our share price may be more volatile. are accustomed to receiving or in a manner in which you are accustomed to receiving it. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to As a foreign private issuer, the rules governing the information that we private companies. We have irrevocably elected not to avail ourselves of disclose differ from those governing U.S. corporations pursuant to the this exemption from new or revised accounting standards, and, therefore, we Securities Exchange Act of 1934, as amended, or the Exchange Act. Although will be subject to the same new or revised accounting standards as other we intend to report quarterly financial results and report certain material public companies that are not emerging growth companies. GeoPark 20F 57 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 We have evaluated our internal controls for our financial reporting and have you might seek to make. determined our controls were effective for the fiscal year ended December 31, The Bermuda Monetary Authority, or the BMA, must specifically approve all 2014. As long as we qualify as an “emerging growth company” as defined issuances and transfers of securities of a Bermuda exempted company like by the Jumpstart our Business Startups Act of 2012, we will not be required to us unless it has granted a general permission. We are able to rely on a general obtain an auditor’s attestation report on our internal controls in future annual permission from the BMA to issue our common shares, and to freely transfer reports on Form 20-F as otherwise required by Section 404(b) of the Sarbanes- of our common shares as long as the common shares are listed on the NYSE Oxley Act. Accordingly, our independent registered public accounting firm and/or other appointed stock exchange, to and among persons who are did not perform an audit of our internal control over financial reporting for the non-residents of Bermuda for exchange control purposes. Any other transfers fiscal year ended December 31, 2014. Had our independent registered public remain subject to approval by the BMA and such approval may be denied accounting firm performed an attestation on our internal control over financial or delayed. reporting, it is possible that their opinion on our internal controls could have differed from ours which could harm our reputation and share value. We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. We will continue to incur significantly increased costs and devote substantial management time as a result of operating as a public company. We are incorporated as an exempted company under the laws of Bermuda and substantially all of our assets are located in Chile, Colombia, Argentina, Our recent initial public offering in February 2014 had a transformative Brazil and will be located additionally in Peru. In addition, most of our effect on us. We expect to incur significant legal, accounting, reporting and directors and executive officers reside outside the United States and all or a other expenses as a result of having publicly traded common shares listed on substantial portion of the assets of such persons are located outside the the NYSE. We may also continue to incur costs which we have not incurred United States. As a result, it may be difficult or impossible to effect service of previously, including, but not limited to, costs and expenses for directors’ process within the United States upon us, or to recover against us on fees, increased directors and officers insurance, investor relations, and various judgments of U.S. courts, including judgments predicated upon the civil other costs of a public company. liability provisions of the U.S. federal securities laws. Further, no claim may be brought in Bermuda against us or our directors and officers in the first We also anticipate that we will incur costs associated with corporate instance for violation of U.S. federal securities laws because these laws have governance requirements, including requirements under the Sarbanes Oxley no extraterritorial application under Bermuda law and do not have force Act of 2002, as well as rules implemented by the SEC and NYSE. We expect of law in Bermuda. However, a Bermuda court may impose civil liability, these rules and regulations to increase our legal and financial compliance including the possibility of monetary damages, on us or our directors and costs and make some management and corporate governance activities more time-consuming and costly, particularly after we are no longer an “emerging officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. growth company.” These rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance, There is no treaty in force between the United States and Bermuda providing and we may be required to accept reduced policy limits and coverage or incur for the reciprocal recognition and enforcement of judgments in civil and substantially higher costs to obtain the same or similar coverage. This could commercial matters. As a result, whether a United States judgment would have an adverse impact on our ability to recruit and bring on a qualified be enforceable in Bermuda against us or our directors and officers depends independent board. on whether the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, The additional demands associated with being a public company listed as determined by reference to Bermuda conflict of law rules. A judgment on the NYSE may disrupt regular operations of our business by diverting the debt from a U.S. court that is final and for a sum certain based on U.S. federal attention of some of our senior management team away from revenue- securities laws will not be enforceable in Bermuda unless the judgment producing activities to management and administrative oversight, adversely debtor had submitted to the jurisdiction of the U.S. court, and the issue of affecting our ability to attract and complete business opportunities and submission and jurisdiction is a matter of Bermuda (not U.S.) law. increasing the difficulty in both retaining professionals and managing and growing our businesses. Any of these effects could harm our business, In addition, and irrespective of jurisdictional issues, the Bermuda courts will financial condition and results of operations. not enforce a U.S. federal securities law that is either penal or contrary to 58 GeoPark 20F Bermuda public policy. An action brought pursuant to a public or penal law, agreement to be approved by the company’s board of directors and by its the purpose of which is the enforcement of a sanction, power or right at the shareholders. Shareholder approval is not required where (i) the holding instance of the state in its sovereign capacity, will not be entertained by a company and one or more of its wholly-owned subsidiary companies Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, amalgamate or merge or (ii) two or more wholly-owned subsidiary companies including certain remedies under U.S. federal securities laws, would not be of the same holding company amalgamate or merge. Save for such “short- available under Bermuda law or enforceable in a Bermuda court, as they form” amalgamations or mergers, unless the company’s bye-laws provide would be contrary to Bermuda public policy. otherwise, the approval of 75% of the shareholders voting at such meeting is required to approve the amalgamation or merger agreement, and the Bermuda law differs from the laws in effect in the United States and might quorum for such meeting must be two persons holding or representing more afford less protection to shareholders. 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 Our shareholders could have more difficulty protecting their interests than and of our shareholders by Special Resolution, meaning a resolution adopted would shareholders of a corporation incorporated in a jurisdiction of the by 65% of more of the votes cast by shareholders who (being entitled to do United States. As a Bermuda company, we are governed by our memorandum so) vote in person or by proxy at any general meeting of the shareholders of association and bye-laws and Bermuda company law. The provisions in accordance with the provisions of the bye-laws. Under Bermuda law, in the of the Bermuda Companies Act, which applies to us, differs in some material event of an amalgamation or merger of a Bermuda company with another respects from laws generally applicable to U.S. corporations and shareholders, company or corporation, a shareholder of the Bermuda company who is not including the provisions relating to interested directors, mergers and satisfied that fair value has been offered for such shareholder’s shares may, acquisitions, takeovers, shareholder lawsuits and indemnification of directors. within one month of notice of the shareholders meeting, apply to the Set forth below is a summary of these provisions, as well as modifications Supreme Court of Bermuda to appraise the fair value of those shares. Under adopted pursuant to our bye-laws, which differ in certain respects Delaware law, with certain exceptions, a merger, consolidation or sale of all from provisions of Delaware corporate law. Our shareholders approved the or substantially all the assets of a corporation must be approved by the adoption of new bye-laws which came into effect on February 19, 2014, being board of directors and a majority of the issued and outstanding shares the date on which the company cancelled admission of its common shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation on AIM. Because the following statements are summaries, they do not discuss participating in certain major corporate transactions may, under certain all aspects of Bermuda law that may be relevant to us and our shareholders. circumstances, be entitled to appraisal rights pursuant to which such Interested Directors. Under our bye-laws and The Companies Act, 1981(as amended) of Bermuda, or the Bermuda Companies Act, a director shall declare the nature of his interest in any contract or arrangement with the shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction. company. Our bye-laws further provide that a director so interested shall not, except in particular circumstances, be entitled to vote or be counted in the quorum at a meeting in relation to any resolution in which he has an interest, Shareholders’ Suit. Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action which is to his knowledge, a material interest (otherwise than by virtue in the name of a company to remedy a wrong to the company where the of his interest in shares or debentures or other securities of or otherwise in act complained of is alleged to be beyond the corporate power of the company or through the company). In addition, the director will not be liable to us for or illegal, or would result in the violation of the company’s memorandum any profit realized from the transaction. In contrast, under Delaware law, of association or bye-laws. Furthermore, consideration would be given by a such a contract or arrangement is voidable unless it is approved by a majority Bermuda court to acts that are alleged to constitute a fraud against the minority of disinterested directors or by a vote of shareholders, in each case if the shareholders or where an act requires the approval of a greater percentage of material facts as to the interested director’s relationship or interests are the company’s shareholders than that which actually approved it. disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved When the affairs of a company are being conducted in a manner which is or ratified. Additionally, such interested director could be held liable for a oppressive or prejudicial to the interests of some part of the shareholders, transaction in which such director derived an improper personal benefit. one or more shareholders may apply under the Bermuda Companies Act for Amalgamations, Mergers and Similar Arrangements. Pursuant to the Bermuda Companies Act, the amalgamation or merger of a Bermuda company with an order of the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders another company or corporation requires the amalgamation or merger by other shareholders or by the company. GeoPark 20F 59 Our bye-laws contain a provision by virtue of which we and our shareholders Undertaking Tax Protection Act 1966, as amended, an assurance that, in waive any claim or right of action that they have, both individually and on our the event that Bermuda enacts legislation imposing tax computed on profits, behalf, against any director or officer in relation to any action or failure to take income, any capital asset, gain or appreciation, or any tax in the nature of estate action by such director or officer, except in respect of any fraud or dishonesty duty or inheritance, then the imposition of any such tax shall not be applicable of such director or officer. Class actions and derivative actions generally are to us or to any of our operations or shares, debentures or other obligations, available to shareholders under Delaware law for, among other things, breach until March 31, 2035. We could be subject to taxes in Bermuda after that date. of fiduciary duty, corporate waste and actions not taken in accordance with This assurance is subject to the provision that it is not to be construed to applicable law. In such actions, the court has discretion to permit the winning prevent the application of any tax or duty to such persons as are ordinarily party to recover attorneys’ fees incurred in connection with such action. resident in Bermuda or to prevent the application of any tax payable in Indemnification of Directors. We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching accordance with the provisions of the Land Tax Act 1967 or otherwise payable in relation to any property leased to us. We are incorporated in Bermuda as an exempted company and pay annual Bermuda government fees. In addition, to them by virtue of any rule of law in respect of any negligence, default, all entities employing individuals in Bermuda are required to pay a payroll tax breach of duty or breach of trust of which a director or officer may be guilty and there are other sundry taxes payable, directly or indirectly, to the Bermuda in relation to the company other than in respect of his own fraud or government. Neither we nor our Bermuda subsidiaries employ individuals in dishonesty. Our bye-laws provide that we shall indemnify our officers and Bermuda as at the date of this annual report. directors in respect of their acts and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to The transfer of our common shares may be subject to capital gains taxes which such Director is not legally entitled, and (by incorporation of the pursuant to indirect transfer rules in Chile. provisions of the Bermuda Companies Act) that we may advance moneys to our officers and directors for the costs, charges and expenses incurred by In September 2012, Chile established “indirect transfer rules,” which impose our officers and directors in defending any civil or criminal proceedings taxes, under certain circumstances, on capital gains resulting from indirect against them on condition that the directors and officers repay the moneys transfers of shares, equity rights, interests or other rights in the equity, if any allegations of fraud or dishonesty is proved against them provided, control or profits of a Chilean entity, as well as on transfers of other assets and however, that, if the Bermuda Companies Act requires, and advancement of property of permanent establishments or other businesses in Chile, or the expenses shall be made only upon delivery to the Company of an Chilean Assets. As we indirectly own Chilean Assets, the indirect transfer rules undertaking, by or on behalf of such indemnitee, to repay all amounts if it would apply to transfers of our common shares provided certain conditions shall ultimately be determined by final decision that such indemnitee is outside of our control are met. If such conditions were present and as a not entitled to be indemnified for such expenses under our Bye-law. Under result the indirect transfer rules were to apply to sales of our common shares, Delaware law, a corporation may indemnify a director or officer of the such sales would be subject to indirect transfer tax on the capital gain that corporation against expenses (including attorneys’ fees), judgments, fines may be determined in each transaction. For a description of the indirect and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director transfer rules and the conditions of their application see “-Item 10. Additional Information-E. Taxation-Chilean tax on transfers of shares.” or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with Our common shares will for a time trade on two separate stock markets, respect to any criminal action or proceeding, such director or officer had no and investors seeking to take advantage of price differences between such reasonable cause to believe his or her conduct was unlawful. In addition, we markets may create unexpected volatility in our share price; in addition, have entered into customary indemnification agreements with our directors. investors may not be able to easily move common shares for trading As a result of these differences, investors could have more difficulty between such markets. protecting their interests than would shareholders of a corporation Our common shares are currently registered on the NYSE and the Santiago incorporated in the United States. Offshore Stock Exchange. Although we intend to de-register from the We may become subject to taxes in Bermuda after March 31, 2035, which will be traded on two markets for a period of time. During such time, price may have a material adverse effect on our results of operations. levels for our common shares could fluctuate between markets, independent of our share price on the other market. Investors could seek to sell or buy Under current Bermuda law, we are not subject to tax on income or capital our common shares to take advantage of any price differences between the gains. We have received from the Minister of Finance under The Exempted markets through a practice referred to as arbitrage. Any arbitrage activity Santiago Offshore Stock Exchange as soon as practicable, our common shares 60 GeoPark 20F could create unexpected volatility in the price of our common shares on As of December 31, 2014, we had net proved reserves of 43.7 mmboe the NYSE. (composed of 72 % oil and 28% natural gas), of which 12.1 mmboe, or 28%, of which 24.7 mmboe, or 57% and 6.9 mmboe, or 16 %, were in Chile, Colombia and Brazil respectively. Additionally, according to the D&M Reserves ITEM 4. INFORMATION ON THE COMPANY Report, as of December 31, 2014, the Morona Block in Peru had net proved reserves, of 18.8 mmboe (composed of 100% oil). We expect to close the A. History and development of the company pending Morona Block Acquisition in 2015. General We were incorporated as an exempted company pursuant to the laws of We have built our company around three principal capabilities: Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, our shareholders approved a change in our name to GeoPark Limited, • as an Explorer, which is our ability, experience, methodology and creativity to find and develop oil and gas reserves in the subsurface, based on the effective from July 31, 2013. We maintain a registered office in Bermuda best science, solid economics and ability to take the necessary managed risks. at Cumberland House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. • as an Operator, which is our ability to execute in a timely manner and Our principal executive offices are located at Nuestra Señora de los to have the know-how to profitably drill for, produce, treat, transport and sell Ángeles 179, Las Condes, Santiago, Chile, telephone number +562 2242 9600, our oil and gas – with the drive and persistence to find solutions, overcome and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number obstacles, seize opportunities and achieve results. +5411 4312 9400. Our website is www.geo-park.com. The information on • as a Consolidator, which is our ability and initiative to assemble the right our website does not constitute part of this annual report. balance and portfolio of upstream assets in the right hydrocarbon basins Our company We are an independent oil and natural gas exploration and production, in the right regions with the right partners and at the right price – coupled with the visions and skills to transform and improve value above ground. or E&P, company with operations in Latin America and a proven track record We believe that our risk and capital management policies have enabled of growth in production, reserves and cash flows since 2006. We operate us to compile a geographically diverse portfolio of properties that balances in Chile, Colombia, Brazil and to a lesser extent in Argentina. We also plan to exploration, development and production of oil and gas. These attributes expand our footprint to Peru as a result of our pending Morona Block have also allowed us to raise capital and to partner with premier international acquisition, which is expected to close in 2015. See “-B. Business Overview- companies. Finally, we believe we have developed a distinctive culture within Our operations-Operations in Peru.” our organization that promotes and rewards partnership, entrepreneurship and merit. Consistent with this approach, all of our employees are eligible We have a well-balanced portfolio of assets that includes working and/or to participate in our long-term incentive program, or our Performance-Based economic interests in 29 hydrocarbons blocks, 28 of which are onshore Employee Long- Term Incentive Program. See “-Item 6. Directors, Senior blocks, including 12 in production as of December 31, 2014, as well as an additional shallow- offshore concession in Brazil that includes the Manatí Management and Employees-B. Compensation-Performance-Based Employee Long-Term Incentive Program.” Field. In addition, we have one new concessions in Brazil, the PN-T-597 Block that is still subject to the entry into the concession agreement by the In Chile, we are the first and the largest non-state controlled oil and gas ANP and the Morona Block in Peru, which we expect will close in 2015 producer. We began operations in 2006 in the Fell Block and have evolved from following regulatory approvals. having a non-operated, non-producing interest to having a fully-operated and producing asset with 11.5 mmboe of net proved reserves as of December 31, We produced a net average of 19,653 boepd during the year ended 2014 and average production of 5,850 boepd in 2014. In addition, we operate December 31, 2014, 31.1 %, 55.0 %, 13.6% and 0.3% were in Chile, Colombia, five other hydrocarbon blocks in Chile with significant prospective resources, Brazil and Argentina, respectively, and of which 74% was oil. As we did with three of them in production as of December 31, 2014. not acquire our interest in the Manatí Field until March 31, 2014, the numbers in the preceding sentences do not account for the first quarter production In Colombia, following our successful acquisitions of Winchester, Luna and of the Manatí Field which reached 3,667 boepd. Had the Manatí Field Cuerva in early 2012, we have an asset base of 11 hydrocarbon blocks where been acquired January 1, 2014, production would have been a net average we were able to perform an active exploration and development drilling of 20,557 boepd during the year ended December 31, 2014, 29.7 %, 52.6 %, campaign, which resulted in multiple new oilfield discoveries and to increase 17.4% and 0.3% were in Chile, Colombia, Brazil and Argentina, respectively, average production from 2,965 boepd for the month of April 30, 2012 (the and of which 71% was oil. first full month following our Colombian acquisitions) to 11,615 boepd in the GeoPark 20F 61 fourth quarter of 2014. Total net production in Colombia averaged 10,807 Park currently serves as our Chief Executive Officer and Deputy Chairman, and boepd in 2014. As of December 31, 2014, we had net proved reserves of both actively contribute to our ongoing operations and business decisions. 24.7 mmboe in Colombia, which represents a 169% increase as compared to 9.4 mmboe in 2013, mainly resulting from net additions of proved reserves Our history commenced with the purchase of AES Corporation’s upstream related to field delineation and the appraisal of the Tigana field in the Llanos oil and natural gas assets in Chile and Argentina. Those assets included a 34 Block. We discovered the Tigana oil field in December 2013 and, since non-operating working interest in the Fell Block in Chile, which at that time that time, we have moved efficiently to drill eight wells, including seven wells was operated by the Empresa Nacional de Petróleo, or ENAP, the Chilean in production with a total current rate of approximately 11,000 bopd gross. state-owned hydrocarbon company, and operating working interests in the In May 2013 we agreed to acquire Rio das Contas from Panoro, which holds which we collectively refer to as the Argentina Blocks. Since 2002, our Del Mosquito, Cerro Doña Juana and Loma Cortaderal Blocks in Argentina, a 10% working interest in the shallow offshore Manatí Field, the largest business has grown significantly. non-associated gas field in Brazil, which produced approximately 6 % of the gas produced in Brazil in December 31, 2014. Rio das Contas’s 10% working In 2006, after demonstrating our technical expertise and committing to interest in the Manatí Field represented 3,572 boepd of production during an exploration and development plan, we obtained a 100% operating the year ended December 31, 2014. As of December 31, 2014, we had working interest in the Fell Block by the Republic of Chile. Also in 2006, the net proved reserves of 6.9 mmboe corresponding to Manatí. Separately, in International Finance Corporation, or the IFC, a member of the World September 2013, we entered into concession agreements with the ANP Bank Group, became one of our principal shareholders, and we listed our relating to seven new concessions in the onshore Recôncavo Basin in the common shares on AIM, a market operated by the London Stock Exchange State of Bahia and in the onshore Potiguar Basin in the State of Rio Grande plc, in an initial public offering of common shares outside the United do Norte, or, our Round 11 concessions, and in November 2013, the ANP States. Subsequently, in 2008 and 2009, we issued and sold additional awarded us two additional concessions in the Parnaíba Basin in the State of common shares outside the United States. Maranhão and the Sergipe Alagoas Basin in the State of Alagoas, one of them still subject to the entry into the concession agreement, on our Round In 2008 and 2009, we continued our growth in Chile by acquiring operating 12 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 October 2014, we executed a Joint Investment Agreement and Joint Operating Agreement with Petroperú to acquire an interest in and operate In 2010, we formed a strategic partnership with LGI, a Korean conglomerate, the Morona Block located in northern Peru. We will assume a 75% working to jointly acquire and develop upstream oil and gas projects in Latin interest with Petroperú retaining a 25% working interest. The Morona America. LGI’s business includes a portfolio of energy and raw material Block covers an area of 1.9 million acres on the western side of the Marañón projects, including oil and gas projects in the Middle East and in Southeast Basin, one of the most prolific hydrocarbon basins in Peru. The Morona and Central Asia. 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 In 2011, ENAP awarded us the opportunity to obtain operating working of 35-36° API oil each) and by 3D seismic. We believe that this project will interests in each of the Isla Norte, Flamenco and Campanario Blocks in Tierra significantly increase GeoPark’s overall inventory of exploration resources del Fuego, Chile, which we refer to collectively as the Tierra del Fuego Blocks, and complement our reserves and cash flow base already established and in 2012, jointly with ENAP we entered into special operation contracts in Colombia, Chile and Brazil. The Morona Block includes geophysical surveys (Contratos Especiales de Operación para la Exploración y Explotación de of 2,783 km (2D seismic) and 465 sq km (3D seismic), and an operating field Yacimientos de Hidrocarburo, or CEOPs) with Chile for the exploration and camp and logistics infrastructure. As of December 31, 2014, D&M certified exploitation of hydrocarbons within these blocks. net proved reserves, of 18.8 mmboe in the Morona Block, composed of 100% oil. We expect to close the pending Morona Block Acquisition in 2015. 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, equity interest in GeoPark TdF S.A., or GeoPark TdF, for US$148.0 million. LGI also provided to GeoPark TdF US$84.0 million in standby letters of credit to partially secure the US$101.4 million performance bond required by who have over 25 and 35 years of international oil and natural gas experience, the Chilean government to guarantee GeoPark TdF’s obligations with respect respectively, and who collectively hold approximately 26% of our common to the minimum work program under the Tierra del Fuego CEOPs. Our shares as of the date of this annual report, and are involved in our operations agreement with LGI in the Tierra del Fuego Blocks allows us to earn back up and strategy. Mr. O’Shaughnessy currently serves as our Chairman and Mr. to 12% equity participation in GeoPark TdF, depending on the success of our 62 GeoPark 20F operations in Tierra del Fuego. See “-Item 10. Additional Information-C. consists of Pluspetrol (operator with a 72% working interest), EMESA Material contracts.” (non-operator with a 10% working interest) and GeoPark (non-operator with an 18% working interest). In the first quarter of 2012, we moved into Colombia by acquiring three privately held E&P companies, Winchester, Luna and Cuerva. These acquisitions In October 2014, we entered into an agreement to expand into Peru (our provided us with an attractive platform in Colombia that includes working fifth country platform in Latin America) through the pending acquisition of interests and/or economic interests in 10 blocks located in the Llanos, Morona Block in a joint venture with Petroperú. The Morona Block covers Magdalena and Catatumbo Basins and covering an area of 575,700 gross acres. an area of 1.9 million acres in the prolific Marañon Basin. Pursuant to the terms of the agreement we will assume a 75% working interest of the Morona In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia Block, with Petroperú retaining a 25% working interest. The Morona Block for US$20.1 million, including the assumption of existing debt and the contains the Situche Central oil field, which has been delineated by two wells commitment to provide additional funding to cover LGI’s share of required (with short term tests of approximately 2,400 and 5,200 bopd of 35-36° future investments in Colombia. In addition, our agreement with LGI in API oil each). The Morona Block includes geophysical surveys of 2,783 km Colombia allows us to earn back up to 12% of equity participation in GeoPark (2D seismic) and 465 sq km (3D seismic), and an operating field camp Colombia, depending on the success of our operations in Colombia. See and logistics infrastructure. The area has undergone oil and gas exploration “-Item 10. Additional Information-C. Material contracts.” We and LGI also activities for the past 20 years, and there exist ongoing association agreed that we would extend our strategic partnership to build a portfolio of agreements and cooperation projects with the local communities. The upstream oil and gas assets throughout Latin America through 2015. We expected work program and development plan for the Situche Central believe our partnership with LGI represents a positive independent oil field is to be completed in three stages. The goal of the initial stage will assessment and validation of the quality of our Chilean and Colombian asset be to put the field into production through a long term test to help inventory, the extent of our technical and operational expertise and the determine the most effective overall development plan and to begin to ability of our management to structure and effect significant transactions. generate cash flow. This initial stage requires an investment of approximately In May 2013, we entered into agreements to expand our operations to Brazil. 24 months after closing. We have committed to carry Petroperú, by paying See “-B. Business overview-Our operations-Operations in Brazil.” its portion of the required investment in this initial phase. In November 2014, $140 million to $160 million and is expected to be completed within 18 to we further expanded our portfolio in Colombia through an agreement On September 30, 2013, we entered into a strategic alliance with Tecpetrol S.A. with SK Innovation (a subsidiary of SK Group, the Korean integrated energy (the oil and gas subsidiary of the Techint Group) or Tecpetrol, to jointly identify, and petrochemical company) to farm-in to the CPO-4 Block, located in the study and potentially acquire upstream oil and gas opportunities in Brazil, Llanos Basin. We and SK Innovation have jointly identified new prospects in with a specific focus on the Parnaíba, Sao Francisco, Recôncavo, Potiguar and this Block similar to prospects and leads in our Llanos 34 Block. The above Sergipe Alagoas basins. Tecpetrol has an extensive track record as an oil mentioned farm-in agreement, is subject to regulatory approval in Colombia. and gas explorer and operator throughout the Americas. As part of our strategic alliance with Tecpetrol, we expect to enter into an agreement to jointly In 2014, two years after beginning operations in Colombia, and as a result develop, by assigning to Tecpetrol 50% of our working interest in, the PN-T- of well drilling, production information and 3D seismic mapping, we have been 597 concession in the Parnaíba Basin in the State of Maranhão, which we were able to increase our proved reserves in Colombia by 169% to 24.7 mmboe awarded by the ANP, subject to the entry into the concession agreement. compared to 9.4 mmboe in 2013, mainly from net additions of proved reserves related to field delineation and appraisal of the Tigana field in the Llanos 34 On July 23, 2014, during the 2014 Colombia Bidding Round, carried out by Block. Tigana oil field was discovered in December 2013 and, since that time, the ANH for the VIM -3 Block, we were awarded a new exploratory license. We we have moved efficiently to drill eight wells, including seven wells in production believe the Block has attractive oil and gas exploration potential in a large with a total current rate of approximately 11,000 bopd gross. The Tigana field area within a proven hydrocarbon system, surrounded by existing oil and gas represents a combination trap with a structural component (to the east, west fields and with sparse exploration activity carried out to date. and north) and a stratigraphic component (to the south). Oil has been tested On August 20, 2014, the consortium of GeoPark and Pluspetrol was awarded Additional appraisal drilling is still required to delineate the Tigana field. 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 See “-Item 3. Key Information-D. Risk factors-Risks relating to our business” Mendocina de Energía S.A. (“EMESA”). The blocks are located in the Neuquen and “-B. Business overview-Significant agreements-Peru-Morona Block Basin, Argentina’s largest producing hydrocarbon basin. The consortium Acquisition.” and is being produced from both the Mirador and Guadalupe formations. GeoPark 20F 63 B. Business overview We are an independent oil and natural gas exploration and production, or productive wells, a 72% success ratio. We have grown our business through winning new licenses and acquiring strategic assets and businesses, with E&P, company with operations in Latin America and a proven track record of 24 new blocks incorporated into our portfolio since January 1, 2006. Since our growth in production, reserves and cash flows since 2006. We operate in Chile, inception, we have supported our growth through our prospect development Colombia, Brazil and, to a lesser extent, in Argentina. We may also commence efforts and our drilling program, as well as by developing long-term strategic operations in Peru, pending the acquisition of the Morona Block which is partnerships and alliances with key industry participants, accessing debt subject to regulatory approvals, though there can be no assurance that we will and equity capital markets and developing and retaining a technical team close the acquisition and benefit from production in the Morona Block. with vast experience and a successful track record of finding and producing We have a well-balanced portfolio of assets that includes working and/or experienced team of geologists, geophysicists and engineers, including economic interests in 29 hydrocarbons blocks, 28 of which are onshore blocks, professionals with specialized expertise in the geology of Chile, Colombia, oil and gas in Latin America. A key factor behind our success ratio is our including 12 in production as of December 31, 2014, as well as an additional Brazil, Argentina and Peru. shallow-offshore concession in Brazil that includes the Manatí Field. We have one new concession in Brazil, the PN-T-597 Block that is still subject to the entry For the year ended December 31, 2014, we drilled 53 new wells, 32 into the concession agreement by the ANP and the Morona Block, which we in Chile and 21 in Colombia in blocks in which we have working interests expect will close in 2015 following regulatory approvals. and/or economic interests. Our capital expenditures of US$238 million (US$161 million, US$66 million, and US$11 million in Chile, Colombia, and We produced a net average of 19,653 boepd during the year ended Brazil, respectively) for the year ended December 31, 2014 including December 31, 2014, 31.1% of which was produced in Chile, 55.0% of which was US$110 million related to exploration. produced in Colombia, 13.6% of which was produced in Brazil and 0.3% of which was produced in Argentina, and of which 74% was oil. Average oil In March 2014, we invested US$140 million in Brazil (US$115.0 million net and gas production in 2014 represented a 45% increase as compared to our of cash acquired) for the acquisition of Rio das Contas, which we financed average oil and gas production for the year ended December 31, 2013 of through the incurrence of a loan of US$70.5 million and cash on hand. 13,517 boepd. Oil production increased by 31% to 14,541 bopd (consisting of 3,690 bopd, 10,748 bopd, 42 bopd and 61 bopd in Chile, Colombia, Brazil and In October 2014, we executed a Joint Investment Agreement and Joint Argentina, respectively) for the year ended December 31, 2014, as compared Operating Agreement with Petroperú to acquire an interest in and operate to 11,113 bopd for the year ended December 31, 2013. Gas production the Morona Block located in northern Peru. We will assume a 75% working increased by 112% to 30,677 mcfpd (consisting of 14,484 mcfpd, 354 mcfpd, interest with Petroperú retaining a 25% working interest. The Morona 15,753 mcfpd and 86 mcfpd in Chile, Colombia, Brazil and Argentina, Block covers an area of 1.9 million acres on the western side of the Marañón respectively) for the year ended December 31, 2014, as compared to 14,419 Basin, one of the most prolific hydrocarbon basins in Peru. The Morona mcfpd for the year ended December 31, 2013. As we did not acquire our Block contains the Situche Central oil field, which has been delineated by interest in the Manatí Field until March 31, 2014, the numbers in the preceding sentences do not account for the first quarter production of the Manatí Field two wells (with short term tests of approximately 2,400 and 5,200 bopd of 35-36° API oil each) and by 3D seismic. We believe that this project will which reached 3,667 boepd. Had the Manatí Field been acquired January 1, significantly increase GeoPark’s overall inventory of exploration resources 2014, production would have been a net average of 20,557 boepd during the and complement our reserves and cash flow base already established in year ended December 31, 2014, 29.7 %, 52.6 %, 17.4% and 0.3% were in Chile, Colombia, Chile and Brazil. The Morona Block includes geophysical surveys Colombia, Brazil and Argentina, respectively, and 71% of which was oil. of 2,783 km (2D seismic) and 465 sq km (3D seismic), and an operating field camp and logistics infrastructure. As of December 31, 2014, D&M certified As of December 31, 2014, we had net proved reserves of 43.7 mmboe net proved reserves, of 18.8 mmboe in the Morona Block, composed of 100% (composed of 72% oil and 28% natural gas), of which 12.1 mmboe, or 28%, oil. We expect to close the pending Morona Block Acquisition in 2015. of which 24.7 mmboe, or 57% and 6.9 mmboe, or 16%, were in Chile, Colombia and Brazil respectively. Additionally, according to the D&M Reserves Report, as of December 31, 2014, the Morona Block had net proved reserves, Oil industry situation and the impact on GeoPark’s operations As a consequence of the oil price crisis which started in the second half of of 18.8 mmboe (composed of 100% oil). We expect to close the pending 2014 (WTI and Brent, the main international oil price markers, fell by Morona Block Acquisition in 2015. approximately 50% between August 2014 and March 2015), the Company has undertaken a decisive cost cutting program to ensure its ability to We have been able to successfully develop our assets through drilling, with both maximize the work program and preserve its cash. For more information 147 of the 205 wells that we drilled from 2006 through 2014 having become see “-Item 3. Key Information-D. Risk Factors-Risks relating to our business- 64 GeoPark 20F Current oil industry price crisis and the impact on GeoPark’s operations” The following map shows the countries in which we have blocks with working and “-Item 4. Information on the Company-B. Business Overview-2015 and/or economic interests as of December 31, 2014 and also includes our Strategy and Outlook.” pending Morona Block Acquisition. For information on our working interests in each of these blocks, see “-Our assets” below. Colombia Blocks C O L O M B I A La Cuerva Llanos 34 Llanos 62 Yamu Llanos 17 Llanos 32 Abanico Cerrito Jagüeyes VIM - 3 CPO - 04 (1) Chile Blocks Fell Tranquilo Otway Isla Norte Campanario Flamenco P E R U B R A Z I L Peru Blocks Morona (2) P A C I F I C O C E A N A R G E N T I N A C H I L E Brazil Blocks POT - T 619 POT - T 620 POT - T 663 POT - T 664 POT - T 665 REC - T 85 REC - T 94 BCAM - 40 (Manati) SEAL - T 268 PN - T 597 (3) A T L A N T I C O C E A N Argentina Blocks Del Mosquito Sierra del Nevado Puelen (1) Subject to the approval of ANH in Colombia. (3) The PN-T-57 is still subject to an injunction and our bid for the concession (2) We expect to close the transaction in 2015 following regulatory approvals. has been suspended. See “-Our operations-Operations in Brazil.” See “-Our operations-Operations in Peru.” GeoPark 20F 65 The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2014. Country Chile Colombia Brazil Argentina Total Oil (mmbbl) 6.4 24.7 0.1 - 31.4 Gas (bcf) 34.0 - 40.5 - 74.4 Oil equivalent (mmboe) 12.1 24.7 6.9 - 43.7 The following table sets forth the net proved reserves and other data as of and for the year ended December 31, 2014 as estimated in the D&M Reserves Report corresponding to the pending Morona Block Acquisition that we expect to close in 2015. 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, or CAGR, of 34% for production in the period from 2008 to 2014, as measured by boepd in the table below. For the year ended December 31, 2014 Revenues (in thousands of US$) 145,720 246,085 35,621 1,308 428,734 % Oil 53% 100% 2% - 72% % of total revenues 34.0% 57.4% 8.3% 0.3% 100% For the year ended December 31, 2014 Revenues (in thousands of US$) - - % Oil 100% 100% % of total revenues - - Average net production (mboepd) % Oil 2014 19.7 74.0% 2013 13.5 82.2% 2012 11.3 66.3% 2011 7.6 33.0% 2010 6.9 28.4% 2009 6.3 19.5% 2008 3.4 9.8% For the year ended December 31, During the year ended December 31, 2014, Rio Das Contas, whose production is not accounted for in the table above as the transaction closed in March 31, 2014, produced 3.6 mboepd. Had the Manatí Field been acquired January 1, 2014, production would have been a net average of 20,557 during the year ended December 31, 2014. 66 GeoPark 20F The following table sets forth our production of oil and natural gas in the blocks in which we have a working and/or economic interest as of December 31, 2014. Oil production Total crude oil production (bopd) Average sales price of crude oil (US$/bbl) Natural gas production Total natural gas production (mcf/day) Average sales price of natural gas (US$/mcf) Oil and natural gas production cost Weighted average production cost (US$/boe) Average daily production For the year ended December 31, 2014 Chile 3,690 89.4 14,484 6.2 37.6 Colombia Argentina 10,748 73.0 354 - 35.4 61 75.4 86 1.1 26.6 Brazil 42 102.4 15,753 6.5 23.5 Our assets According to the D&M Reserves Report, as of December 31, 2014, the blocks in Chile, Colombia, and Brazil in which we have a working interest had 43.7 mmboe of net proved reserves, with 12.1 mmboe, or 28%, 24.7 mmboe, or 57% and 6.9 mmboe, or 16% of such net proved reserves located in Chile, Colombia and Brazil respectively. Additionally, according to the D&M Reserves Report, as of December 31, 2014, the net proved reserves attributable to our pending Morona Block acquisition in Peru were 18.8 mmboe. We expect to close the pending Morona Block Acquisition in 2015. For the year ended December 31, 2014, we produced an average of 19,653 boepd, of which 6,104 boepd, or 31.1%, was produced in the Chilean blocks, 10,807 boepd, or 55.0%, was produced in the Colombian blocks, 2,668 boepd, or 13.6%, was produced in the Brazilian blocks and 75 boepd or 0.3%, was produced in the Argentine blocks. As we did not acquire our interest in the Manatí Field until March 31, 2014, the numbers in the preceding sentences do not account for the first quarter production of the Manatí Field which reached 3,667 boepd. Had the Manatí Field been acquired January 1, 2014, production would have been a net average of 20,557 boepd during the year ended December 31, 2014, 29.7 %, 52.6 %, 17.4% and 0.3% were in Chile, Colombia, Brazil and Argentina, respectively, and 71% of which was oil. We are the operator of a majority of the blocks in which we have a working interest. The following table summarizes certain information about our Chilean, Colombian, Argentine and Brazilian blocks as of December 31, 2014. GeoPark 20F 67 Country Concession Operator Block/ Working interest (1)(2)(12) Basin Fell Tranquilo(16) Otway GeoPark GeoPark GeoPark 100% Magallanes 29% Magallanes 100% Magallanes Gross area Net proved (thousand acres)(3) 367.8 reserves (mmboe)(4) 11.5 92.4 49.4(6) - - % Oil 53% - - Isla Norte GeoPark 60%(7) Magallanes 130.2 0.06 92% Campanario GeoPark 50%(7) Magallanes 192.2 0.04 100% Flamenco GeoPark 50%(7) Magallanes 141.3 973.3 0.5 12.1 52% 53% 199.1 6,103.6 Chile Chile Chile Chile Chile Chile Subtotal Chile Net production (boepd)(5) 5,849.8 - - 41.4 13.3 Concession % Oil expiration year 61% Exploitation: 2032 - Exploitation: 2043 - Exploitation: 2044 Exploration: 2019 88% Exploitation: 2044 Exploration: 2020 98% Exploitation: 2045 Exploration: 2019 37% Exploitation: 2044 60% Exploration: 2014 Colombia La Cuerva GeoPark 100% Llanos Colombia Llanos 34 GeoPark 45% Llanos Colombia Llanos 62 GeoPark 100% Llanos Colombia Yamú GeoPark 79.5/90%(8) Llanos 47.8 82.2 44.0 11.2 2.6 100% 1,388.8 99% Exploitation: 2038 Exploration: 2015 21.5 100% 8,306.0 100% Exploitation: 2039 - - - - Exploitation: 2041 Exploration: 2017 0.5 100% 388.3 98% Exploitation: 2036 Exploration: 2015 Exploration: 2013 Colombia Llanos 17 Parex 36.8%(9) Llanos 108.8 0.03 100% 52.2 100% Exploitation: 2039 Colombia Llanos 32 Parex 10% Llanos 100.3 0.1 100% 485.6 100% Exploitation: 2039 Exploration: 2015 Colombia Jagu(cid:0) eyes 3432A Columbus 5% Llanos 61.0 Colombia(18) CPO-4 GeoPark 100% Llanos 345.6 Colombia Colombia Colombia Colombia VIM-3 Arrendajo(17) Abanico Cerrito GeoPark 50% Magdalena Pacific Pacific Pacific 0% Llanos 0%(10) Magdalena 0%(10) Catatumbo 225.0 78.1 32.1 10.2 - - - - - - - - - Exploration: 2014 - Exploitation: 2038 Exploration: 2021 - Exploitation: 2045 Exploration: 2015 - Exploitation: 2038 103.1 100% Production: 2041 83 - - - Production: 2022 Production: 2028 - - - - - - Subtotal Colombia 1,146.4 24.7 100% 10,806.9 99% Argentina Argentina Argentina Del Mosquito Puelen(15) Sierra del Nevado(15) Subtotal Argentina GeoPark Pluspetrol 100% 18% Austral 17.3 Neuquén 1,430.0 Pluspetrol 18% Neuquén 305.0 1,752.3 - - - - - - - - 75 - - 75 81% Exploitation: 2016 - Exploitation: 2017 - Exploitation: 2017 81% 68 GeoPark 20F Country Concession Operator Block/ Working interest (1)(2)(12) Basin 100% Recôncavo 100% Recôncavo Gross area Net proved (thousand acres)(3) 7.7 reserves (mmboe)(4) - REC T 94 REC T 85 POT T 664 POT T 665 POT T 619 POT T 620 GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark 100% 100% 100% 100% POT T 663 GeoPark PN T 597(13) GeoPark(14) 100% 100%(14) SEAL T 268 GeoPark BCAM-40 Petrobras Potiguar Potiguar Potiguar Potiguar Potiguar Parnaíba Sergipe Alagoas Camanu- Almada 7.7 7.9 7.9 7.9 7.9 7.9 188.7 7.8 22.8 274.2 Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Subtotal Brazil Total GeoPark Net production (boepd)(5) - - - - - - - - - % Oil - - - - - - - - - - - - - - - - - 6.9 6.9 2% 2% - 2,668(19) Concession % Oil expiration year - Exploration: 2018 - Exploitation: 2045 - Exploration: 2018 - Exploitation: 2045 - Exploration: 2018 - Exploitation: 2045 - Exploration: 2018 - Exploitation: 2045 - Exploitation: 2029(11) 2034(12) - 2% 4,146.1 43.7 72% 19,653 74% (1) Working interest corresponds to the working interests held by our (9) We have a 40% working interest in the Llanos 17 Block, although we respective subsidiaries in such block, net of any working interests and/or have assigned a 3.2% economic interest to a third party. We expect to apply economic interests held by other parties in such block. to formalize this assignment with the ANH so that it will be recognized as a (2) As of December 31, 2014, LGI has a 20% equity interest in our Chilean working interest. operations (through GeoPark Chile), and a 20% equity interest in our (10) We do not have a working interest in those blocks, though we have a Colombian operations through GeoPark Colombia. 10% economic interest in the net revenues of each of these blocks pursuant (3) Gross area refers to the total acreage of each block. to various partnership interests’ agreements. See “-Our operations-Operations (4) Reflects net proved reserves as of December 31, 2014. in Colombia.” (5) Reflects net average production for 2014. Net production refers to average (11) Corresponds to the Manatí Field. production for each block, net of any working interests or economic interests (12) Corresponds to the Camarão Norte Field. held by others in such block but gross of any royalties due to others. (13) PN-T-597 Block subject to the entry into the concession agreement by (6) In April 2013, we voluntarily relinquished to the Chilean government all the ANP and absence of any legal impediments to signing. See “-Item 3. of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our partners under the joint operating agreement governing the Otway Block Key information-D. Risk factors-Risks relating to our business-The PN-T-597 concession is subject to an injunction and may not close.” decided to withdraw from such joint operating agreement, and applied (14) We expect to jointly develop this concession with Tecpetrol and assign for an assignment of rights permit on August 5, 2013. In September 2014, a portion of our working interest in this concession to Tecpetrol. the Chilean Ministry of Energy approved us as the sole participant. See (15) New blocks awarded in the 2014 Mendoza Bidding Round. “-Our operations-Operations in Chile-Otway and Tranquilo Blocks.” (16) At December 31, 2013, the Consortium members and interests were: (7) LGI has a 14% direct equity interest in our Tierra del Fuego operations GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. During through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, 2014 Methanex and Wintershall announced their decision to exit the for a total 31.2% effective equity interest in our Tierra del Fuego operations. Consortium. The new ownership is GeoPark 50% and Pluspetrol 50%. See “-Our operations-Operations in Chile-Tierra del Fuego Blocks (17) On July 29, 2014, our Colombian subsidiary agreed to exchange its 10% (Isla Norte, Campanario and Flamenco Blocks).” non-operating economic interest in the Arrendajo Block for additional (8) Although we are the sole title holder of the working interest in the Yamú interests held by the seller in the Yamú Block that includes a 15% economic Block, other parties have been granted economic interests in fields in interest in all of the Yamú fields except for the Carupana field, where the this block. Taking those other parties’ interests into account, we have a 79.5% seller had a 25% economic interest. interest in the Carupana Field and a 90% interest in the Yamú and Potrillo (18) Subject to regulatory approval from the ANH in Colombia. Fields, both located in the Yamú Block. (19) Considering production since the acquisition date, March 31, 2014. Full year 2014 production amounted to 3,572 boepd (composed of 98% gas). GeoPark 20F 69 The table below summarizes information as of December 31, 2014 regarding the concessions in Peru in which we expected to have a working interest fol- lowing the completion of our pending Morona Block Acquisition. Block Morona Operator GeoPark Working interest(1) 75% Basin Marañon Gross area Net proved (thousand acres) 1,881 reserves (mmboe)(2 ) 18.8 Net production (boepd) - % Oil 100% % Oil - Concession expiration year Exploitation: 2035(3) (1) Corresponds to the initial working interest. Petroperú will have the right The acquisitions of Winchester, Luna and Cuerva in Colombia in the first to increase its working interest in the Block by up to 50%, subject to quarter of 2012 gave us access to an additional 574,979 gross exploratory the recovery of our investments in the Block by certain agreed factors as and productive acres across 10 blocks in what we believe to be one of South described below. America’s most attractive oil and gas geographies. According to the D&M (2) Certified by D&M as of December 31, 2014. Reserves Report, as of December 31, 2014, the blocks in Colombia in which (3) The concession year expiration is related to approval of environmental we have a working interest had 24.7 mmboe of net proved reserves, all impact assessment (EIA) study for project development. The expiration of which were in oil. Since we acquired Winchester, Luna and Cuerva, we were of concession will occur twenty years after EIA approval. We expect the EIA able to perform an active exploration and development drilling campaign, to be approved in approximately in December 2016. which resulted in multiple new discoveries and to increase average Our strengths We believe that we benefit from the following competitive strengths: production to 10,807 boepd in Colombia in 2014. Also, we have been able to leverage our technical expertise achieving significant positive results in terms of reduced drilling costs in our multiple new oilfield discoveries, one of which was located in the hanging wall of a normal fault, a play type High quality and diversified asset base built through a successful track that had not been successfully tested before in the Llanos basin. record of organic growth and acquisitions Our assets include a diverse portfolio of oil- and natural gas-producing The acquisition of Rio Das Contas gave us a 10% working interest in reserves, operating infrastructure, operating licenses and valuable geological the BCAM-40 Concession, including the shallow-depth offshore Manatí and surveys. According to the D&M Reserves Report, as of December 31, 2014, Camarão Norte Fields, in the Camamu-Almada Basin in the State of Bahia. we had 43.7 mmboe of net proved reserves in Chile, Colombia, and Brazil of The Manatí Field, which is in the production phase, is operated by Petrobras which 72%, or 31.3 mmboe, was oil, and 28%, or 12.4 mmboe, was gas and of (with a 35% working interest), the Brazilian national company and the which 32%, or 14.2 mmboe, was net proved developed reserves. Throughout our history, we have delivered continuous growth in our production, and largest oil and gas operator in Brazil, in partnership with QGEP (with a 45% working interest), and Brasoil (with a 10% working interest). See “-Significant our management team has been able to identify under-exploited assets and agreements-Brazil-Rio das Contas Quota Purchase Agreement.” Our Rio turn them into valuable, productive assets. For example, in 2002, we acquired das Contas acquisition in Brazil provides us with a long-term off-take contract a non-operating working interest in the Fell Block in Chile, which at the with Petrobras that covers approximately 74% of net proved gas reserves time had no material oil and gas production or reserves despite having been in the Manatí Field, a valuable relationship with Petrobras and an established actively explored and drilled over the course of more than 50 years. Since local platform and presence, with seasoned and experienced geoscience 2006, when we became the operator of the Fell Block, through 2014, we have and administrative team to manage our Brazilian assets and to seek new invested more than US$510 million and drilled approximately 113 wells growth opportunities. According to the D&M Reserves Report, as of in the Block, with 76% of such wells becoming productive during that period. December 31, 2014, BCAM-40 Concession had 6.9 mmboe of net proved Currently, we are the operator and sole concessionaire of the Fell Block, reserves, (composed of approximately 98% natural gas). See “-Our operations- which, during the year ended December 31, 2014, produced approximately Operations in Brazil.” 5,580 boepd. As of December 31, 2014, we generated 55% of Chile’s total oil production and 16% of its gas production, according to information provided by the Chilean Ministry of Energy. 70 GeoPark 20F In addition, in line with our growth strategy, the pending acquisition of the depending on market prices, and complement our reserves and cash flow Morona Block in Peru will give us a 75% working interest in the Morona Block. base already established in Colombia, Chile and Brazil. As of December 31, According to the D&M Reserves Report, as of December 31, 2014, the 2014, D&M certified net proved reserves, of 18.8 mmboe in the Morona Block Morona Block had 18.8 mmboe of net proved reserves, (composed of 100% composed of 100% oil. We expect to close the pending Morona Block oil). We expect to close the pending Morona Block Acquisition in 2015. Acquisition in 2015. See “-Our operations- Operations in Peru.” Our geoscience team continues to identify new potential accumulations and Significant drilling inventory and resource potential from existing asset expand our inventory of prospects and drilling opportunities. base Our portfolio includes large land holdings in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different Funding Platform We have historically benefited from consistent cash flows and access to geological formations, which provide a number of attractive opportunities debt and equity capital markets, as well as other funding sources, which have with varying levels of risk. Our drilling inventory consists of over 350 provided us in the past with funds to finance our organic growth and the identified drilling locations, and our development plans target locations that pursuit of potential new opportunities. We generated US$230.7 million and provide attractive economics and support a predictable production profile. US$127.3 million in cash from operations in the years ended December 31, Highlights of our 2014 exploration and drilling plan include: 2014 and 2013, respectively, and had US$127.7 million and US$121.1 million in cash and cash equivalents as of December 31, 2014 and 2013, respectively. • In Colombia, in 2014, continued delineation of the Tigana and Tua Fields. As of December 31, 2014 we had US$370 million of total financial debt We discovered the Tigana oil field in December 2013 and, since that time, our with 80% debt maturing in 2020. Our short-term objectives are to preserve team has moved efficiently to drill a total of eight wells; put seven wells in cash, see below “-Our long-term strategy.” production, install facilities and infrastructure to handle approximately 20,000 barrels of fluid per day, with plans underway to expand to 100,000 barrels of In March 2014, we borrowed US$70.5 million pursuant to a five-year term fluid per day. The Tigana field represents a combination trap with a structural variable interest secured loan, secured by the benefits GeoPark receives under component (to the east, west and north) and a stratigraphic component the Purchase and Sale Agreement for Natural Gas with Petrobras, equal (to the south). Oil has been tested and is being produced from both the to six-month LIBOR + 3.9% to finance part of the purchase price of our Rio Mirador (approximately 21-29° API crude oil) and Guadalupe (approximately das Contas acquisition, and funded the remaining amount with cash on 15.5° API crude oil) formations. The expanded Tigana field size represents hand. In March 2015, we reached an agreement to: (i) extend the principal increased value for GeoPark by providing an important opportunity to further payments that were due in 2015 (amounting to approximately US$15 million), grow production and to potentially generate attractive financial returns. In which will be divided pro-rata during the remaining principal installments, addition to improving the overall risk profile of GeoPark’s work program starting in March 2016 and (ii) to increase the variable interest rate equal to inventory, a larger field provides opportunities to reduce drilling, operating the six-month LIBOR + 4.0%. and transportation costs by improved efficiencies. • In Chile, in 2014 we announced the discovery of the Primavera Sur 1 well In February 2014, we commenced trading on the NYSE and raised US$98 that marks the first discovery of an oil field on the Campanario Block in Tierra million (before underwriting commissions and expenses), including the del Fuego, Chile, where we operate and have a 50% working interest in over-allotment option granted to and exercised by the underwriters, through partnership with ENAP. Also in 2014 we announced the successful drilling and the issuance of 13,999,700 common shares. testing of the Ache 1 exploration well located on the Fell Block in Chile. • In Brazil, in 2014 we have acquired seismic data processing with regards to In February 2013, we issued US$300.0 million aggregate principal amount certain of our exploratory blocks in the Reconcavo and Potiguar basins. of 7.50% senior secured notes due 2020, or the “Notes due 2020.” The Notes • In Peru, in 2014 we executed an agreement with Petroperú to acquire a 75% due 2020 contain limitations on the amount of indebtedness we can incur working interest in and operate the Morona Block located in northern Peru. See “-Item 5. Information on the Company-Indebtedness-Notes due 2020- The Morona Block covers an area of 1.9 million acres on the western side Covenants.” of the Marañón Basin, one of the most prolific hydrocarbon basins in Peru. The Morona Block contains the Situche Central oil field, which has been In 2010, we issued US$133.0 million aggregate principal amount of 7.75% delineated by two wells and by 3D seismic. We believe that this project will senior secured notes in the international markets, or the Notes due 2015, significantly increase GeoPark’s overall inventory of exploration resources, which were redeemed following our issuance in 2013 the Notes due 2020. GeoPark 20F 71 In 2007, we obtained financing from Methanex Chile S.A., or Methanex, Throughout our history, our management and operating team has had success the Chilean subsidiary of the Methanex Corporation, a leading global in unlocking unexploited value from previously underdeveloped assets. methanol producer, in an amount of US$40 million, structured as a gas pre-sale agreement with a six-year term at an interest rate equal to In addition, as of the date of this annual report, our executive directors, the six-month LIBOR. management and employees (excluding our founding shareholders, Mr. Gerald E. O’Shaughnessy and Mr. James F. Park) owned 6.9% of our outstanding In 2006, we completed an initial public offering of our common shares common shares, aligning their interests with those of our shareholders outside the United States on AIM and, in 2008 and 2009, we issued and sold and helping retain the talent we need to continue to support our business additional common shares outside the United States. strategy. See “-Item 6. Directors, Senior Management and Employees-B. Compensation.” Our founding shareholders are also involved in our daily In February 2006, the IFC became a significant shareholder by contributing operations and strategy. 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 Long-term strategic partnerships and strong strategic relationships, such as finance our investment program. Highly committed founding shareholders and technical and management with LGI, provide us with additional funding flexibility to pursue further acquisitions We benefit from a number of strong partnerships and relationships. In March teams with proven industry expertise and technically-driven culture Our founding shareholders, management and operating teams have 2010, we entered into a framework agreement with LGI to establish a strategic growth partnership to jointly acquire and invest in oil and natural significant experience in the oil and gas industry and a proven technical and gas projects throughout Latin America. In May 2011, our partnership with LGI commercial performance record in onshore fields, as well as complex projects was strengthened by LGI’s acquisition of a 10% equity interest in our existing in Latin America and around the world, including expertise in identifying Chilean operations. In October 2011, LGI acquired an additional 10% equity acquisition and expansion opportunities. Moreover, we differentiate interest in GeoPark Chile and a 14% equity interest in GeoPark TdF, and ourselves from other E&P companies through our technically-driven culture, agreed to provide additional financial support for the further development which fosters innovation, creativity and timely execution. Our geoscientists, of the Tierra del Fuego Blocks. In December 2012, LGI acquired a 20% equity geophysicists and engineers are pivotal to the success of our business interest in our Colombian business. We also agreed with LGI to extend our strategy, and we have created an environment and supplied the resources strategic partnership in order to build a portfolio of upstream oil and gas that enable our technical team to focus its knowledge, skills and experience assets throughout Latin America through 2015. As of the date of this Annual on finding and developing oil and gas fields. Report, we are the only independent E&P company in which LGI has equity In addition, we strive to provide a safe and motivating workplace for with LGI” for additional information relating to these agreements. investments in Latin America. See “-Significant agreements-Agreements employees in order to attract, protect, retain and train a quality team in the competitive marketplace for capable energy professionals. In addition, the IFC has been one of our shareholders since 2006, holding an 6% equity interest in us as of the date of this Annual Report. In Chile, we Our CEO, Mr. James Park, has been involved in E&P projects in Latin America have strong long-term commercial relationships with Methanex and ENAP, since 1978. He has been closely involved in grass-roots exploration activities, and in Colombia, through our acquisitions of Winchester, Luna and Cuerva, drilling and production operations, surface and pipeline construction, legal we have inherited a strong relationship with Ecopetrol, the Colombian and regulatory issues, crude oil marketing and transportation and capital state-owned oil and gas company. raising for the industry. As of December 31, 2014 Mr. Park held 12.9% of our outstanding common shares. Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in In Brazil, we believe we will continue to derive benefit from the long-term relationship GeoPark Brazil (formerly Rio Das Contas) has with Petrobras. the oil and gas business internationally and in North America since 1976. As of December 31, 2014, Mr. O’Shaughnessy held 13.0% of our outstanding 2015 Strategy and Outlook GeoPark’s strategic approach to 2015 is guided by the following principles: common shares. Our management and operating team has an average experience in the flexibility and maintain balance sheet strength. energy industry of approximately 25 years in companies such as Chevron, • Capital Allocation Discipline: Prioritize lower-risk, higher netback, and San Jorge, Petrobras, Total, Pluspetrol, ENAP and YPF, among others. quicker cash flow generating projects. • Preserve Cash: Work and Investment Reduction program to maintain 72 GeoPark 20F • Do More For Less: Aggressively implement operating, general and based on market conditions, our continued production, decisions by the administrative expense and capital cost reduction measures. operators in blocks where we are not the operator, the success of our drilling • Stay Agile: Continuous monitoring of work programs and adjustments results and future acquisitions. Our future financial condition and liquidity as necessary. will be impacted by, among other factors, our level of production of oil and • Build for Long Term: Protect critical assets, tools and capabilities necessary natural gas and the prices we receive from the sale thereof, the success of for long term stability, and continue to search for potential valuable site our exploration and appraisal drilling program, the number of commercially opportunities. viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries At the base budget oil price assumption of US$45-US$50 per bbl, GeoPark to production and the actual cost of exploration, appraisal and development is targeting a fully-funded US$60 million-US$70 million work and investment of our oil and natural gas assets. program for 2015. The bulk of this 2015 work program is targeted to further develop and produce GeoPark’s Tigana and Tua oil fields in the Llanos 34 Recent developments Block in Colombia, which currently provide the lowest risk production and reserve growth opportunities with attractive operating netbacks. First Quarter 2015 Operational Highlights Our production for the first quarter 2015 has averaged approximately 19,566 boepd, with Colombian, Chilean and Brazilian production representing The work program break-down is approximately as follows: Colombia 11,586 boepd (59%), 4,486 boepd (23%), and 3,494 (18%), respectively. Oil with US$35 million-US$40 million in new drilling and facility construction; and liquids represented 72% of consolidated production. Chile with US$5 million-US$8 million in well workovers and facility construction; Brazil with US$6 million-US$7 million in the Manatí compression Our oil and gas production for the first quarter of 2015 increased 18% to plant installation and seismic processing; Peru with US$8 million-US$9 million 19,586 boepd, compared to 16,583 boepd in the same period in 2014 led mainly in environmental studies and camp facilities; and Argentina with by the strong production growth in the Llanos 34 Block in Colombia which US$3 million-US$4 million in seismic studies. also compensated the temporary shut-in of marginal fields in Colombia and Argentina. Resulting from the above, Colombian, Chilean, Brazilian and If oil prices average higher than the base budget price, GeoPark has the Argentinean production averaged 11,586 boepd (59%), 4,486 boepd ability to allocate additional capital to more projects and increase its work (23%), 3,494 boepd (18%), and 20 boepd (0%), respectively during the first and investment program and thereby further increase oil and gas production. quarter 2015. In budgeting for our future activities, we have relied on a number of Consolidated oil production accounted for 72% of total reported production, assumptions, including, with regard to our discovery success rate, the number increasing to 14,101 bopd in the first quarter 2015 from 13,765 bopd in the of wells we plan to drill, our working interests in our prospects, the costs same period of 2014. involved in developing or participating in the development of a prospect, the timing of third-party projects and our ability to obtain needed financing in respect to any further acquisitions and the availability of both suitable In Colombia, in the Llanos 34 Block, in February 2015, we announced a new oil field discovery following the drilling of exploration well Tilo 1. The equipment and qualified personnel. These assumptions are inherently subject Tilo 1 prospect was defined as a structural trap with three-way dip closure to significant business, political, economic, regulatory, environmental and on the down-thrown side of a normal fault – targeting the two principal competitive uncertainties, conditions in the financial markets, contingencies productive reservoirs, the Guadalupe (main target) and Mirador (secondary and risks, all of which are difficult to predict and many of which are beyond target) sandstones. We drilled and completed the Tilo 1 exploratory well to a our control. In addition, we opportunistically seek out new assets total depth of 11,293 feet in 2014, and successfully tested in the first quarter and acquisition targets to complement our existing operations, and have 2015 with an electrical submersible pump in the Guadalupe formation, at financed such acquisitions in the past through the incurrence of additional approximately 10,707 feet. In March, Tilo 1 well initiated a long-term test, indebtedness, including additional bank credit facilities, equity issuances and is currently on production at a rate of approximately 850 bopd. Further or the sale of minority stakes in certain operations to our partners. We may technical evaluation will also be undertaken to determine if the Tilo field need to raise additional funds more quickly if one or more of our assumptions is potentially a northeast extension of the larger Tigana field. In addition, in prove to be incorrect or if we choose to expand our hydrocarbon asset the first quarter 2014 in the Llanos 34 Block, we tested two appraisal wells, acquisition, exploration, appraisal or development efforts more rapidly than Tua 7 and Tua 9, and these were successfully tested and as of the date we presently anticipate, and we may decide to raise additional funds even of this Annual Report are producing approximately 1,400 and 950 bopd before we need them if the conditions for raising capital are favorable. gross, respectively. Production in Colombia during the first quarter 2015 was The ultimate amount of capital that we will expend may fluctuate materially negatively impacted by the temporary shutdown of oil fields in La Cuerva GeoPark 20F 73 Block, which was producing 880 bopd (La Cuerva Block is located in a more and we expect that our Morona Block in Peru, will provide us with an remote area, and generates higher transportation and logistics expenses). additional attractive platforms in those countries. Our enhanced regional portfolio, primarily in investment-grade countries, and strong partnerships In Chile, the Ache 1 gas discovery well was drilled and completed to a total position us as a regional consolidator. We intend to continue to grow depth of 9,694 feet in 2014. A production test through different chokes through strategic acquisitions and potentially in other countries in Latin in the Tobifera formation resulted in an average gas production rate of America. Our acquisition strategy is aimed at maintaining a balanced portfolio 9.2 million standard cubic feet per day of gas and approximately 80 barrels of lower-risk cash flow-generating properties and assets that have upside per day of condensate of 47 degree API. The well is temporarily shut-in until potential, keeping a balanced mix of oil- and gas-producing assets (though surface facilities are constructed – currently targeted to be completed with we expect to remain weighted towards oil) and focusing on both assets production start-up in 4Q2015. and corporate targets. Our long-term strategy Continue to foster a technically-driven culture and to capitalize on local Continue to grow a risk-balanced asset portfolio We intend to continue to focus on maintaining a risk-balanced portfolio of knowledge We intend to continue to build and strengthen an environment that will assets, combining cash flow-generating assets with upside potential allow us to fully consider and understand risk and reward and to deliberately opportunities, and on increasing production and reserves through finding, and collectively pursue strategies that maximize value. For this purpose, developing and producing oil and gas reserves in the countries in which we we intend to continue expanding our technical teams and to foster a culture operate. For example, through our expansion into Brazil, we have secured that rewards talent according to results. For example, we have been able steady cash flows through our acquisition of Rio das Contas, as well as to maintain the technical teams we inherited through our Colombian exploratory potential through our success in two ANP oil and gas bidding acquisitions and intend to retain our technical teams in Brazil after acquiring rounds in which we were awarded a total of nine concessions in Brazil. Rio das Contas on March 31, 2014. We believe local technical and professional knowledge is key to operational and long-term success and intend to In Peru, the pending acquisition of the Morona Block contains the Situche continue to secure local talent as we grow our business in different locations. Central oil field, which has been delineated by two wells and geophysical surveys, an operating field camp and logistics infrastructure. In addition to the Situche Central field, the Morona Block has a large exploration potential Maintain a high degree of operatorship As of the date of this Annual Report, we are and intend to continue to be, with several high impact prospects and plays. This important component of the operator of a majority of the blocks and concessions in which we have the project will significantly increase our overall inventory of exploration working interests. Operating the majority of our blocks and concessions resources and complement our growing reserve and cash flow base already gives us the flexibility to allocate our capital and resources opportunistically established in Colombia, Chile and Brazil. and efficiently. We believe that this strategy has allowed, and will continue We believe this approach will allow us to sustain continuous and profitable growth and also participate in higher risk growth opportunities with upside operating and management teams. As of December 31, 2014, 84% of our net proved reserves and 83% of our production came from blocks in which we potential. See “-Our operations.” are the operator. to allow, us to leverage our unique culture and our talented technical, Maintain conservative financial policies We seek to maintain a prudent and sustainable capital structure and a strong Maintain our commitment to environmental and social responsibility A major component of our business strategy is our focus on our financial position to allow us to maximize the development of our assets environmental and social responsibility. We are committed to minimizing and capitalize on business opportunities as they arise. We intend to remain the impact of our projects on the environment. We also aim to create financially disciplined by limiting substantially all our debt incurrence to mutually beneficial relationships with the local communities in which identified projects with repayment sources. We expect to continue benefiting we operate in order to enhance our ability to create sustainable value in from diverse funding sources such as our partners and customers in addition our projects. In line with the IFC’s standards, our commitment to our to the international capital markets. environmental and social responsibilities is a major component of our business strategy. These commitments are embodied in our in-house Pursue strategic acquisitions in Latin America We have historically benefited from, and intend to continue to grow through, designed Environmental, Health, Safety and Security management program, which we refer to as “S.P.E.E.D.” (Safety, Prosperity, Employees, Environment strategic acquisitions. Our Colombian acquisitions highlight our ability to and Community Development). Our S.P.E.E.D. program was developed in identify and execute opportunities. These acquisitions have provided us with, accordance with several international quality standards, including ISO 14001 74 GeoPark 20F for environmental management issues, OHSAS 18001 for occupational health and safety management issues, SA 8000 for social accountability and Operations in Chile We became the first privately-owned oil and gas producer in Chile when we workers’ rights issues, and applicable World Bank standards. See “-Health, began production in the Fell Block in May 2006, and, for the year ended safety and environmental matters.” Our operations We have a well-balanced portfolio of assets that includes working and/or December 31, 2014, we produced 55% of Chile’s total oil production and 16% of its total gas production, according to information provided by the Chilean Ministry of Energy. We believe our acreage position in Chile represents a large fully-operated land base across the Magallanes Basin, with existing reserves, economic interests in 29 hydrocarbons blocks, 28 of which are onshore production and cash flows. blocks, including 12 in production as of December 31, 2014, as well as in an additional shallow-offshore concession in Brazil that includes the Manatí The map below shows the location of the blocks in Chile in which we have Field. In addition, we have one new concessions in Brazil, the PN-T-597 Block working interests. that is subject to the entry into the concession agreement by the ANP and the Morona Block in Peru that we expect to close in 2015 following regulatory approvals. C H I L E A R G E N T I N A A R G E N T I N A Tranquilo Otway Fell Isla Norte Campanario Flamenco GeoPark 20F 75 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, 2014. Block Fell Tranquilo Otway Isla Norte Campanario Flamenco Gross acres Working (thousand acres) 367.8 interest (1)(6) 100% Net proved reserves Production (boepd) Basin 5,849.8 Magallanes Exploitation: 2032 Concession expiration year Partners(2) - Pluspetrol; Operator GeoPark (mmboe)(3) 11.5 92.4 49.4(4) Wintershall; 29%(6) Methanex - 100% GeoPark GeoPark 130.2 60%(5) ENAP GeoPark 192.2 50%(5) ENAP GeoPark - - 0.06 0.04 - Magallanes - Magallanes 41.4 Magallanes Exploitation: 2043 Exploitation: 2044 Exploration: 2019 Exploitation: 2044 Exploration: 2020 13.3 Magallanes Exploitation: 2045 Exploration: 2019 141.3 50%(5) ENAP GeoPark 0.5 199.1 Magallanes Exploitation: 2044 (1) Working interest corresponds to the working interests held by our Our Chilean blocks are located in the provinces of Ultima Esperanza, respective subsidiaries in such block, net of any working interests held by Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil- and other parties in such block. LGI has a 20% direct equity interest in our gas-producing area. As of December 31, 2014, the Magallanes Basin Chilean operations through GeoPark Chile. See “-Significant agreements- accounted for all of Chile’s oil and gas production. Although this basin has Agreements with LGI-LGI Chile Shareholders’ Agreements.” been in production for over 60 years, we believe that it remains relatively (2) Partners with working interests. (3) As of December 31, 2014. underdeveloped. (4) In April 2013, we voluntarily relinquished to the Chilean government all Substantial technical data (seismic, geological, drilling and production of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our information), developed by us and by ENAP, provides an informed base for partners under the joint operating agreement governing the Otway Block new hydrocarbon exploration and development. Shut-in and abandoned decided to withdraw from such joint operating agreement, and applied fields may also have the potential to be put back in production by for an assignment of rights permit on August 5, 2013. In September 2014, constructing new pipelines and plants. Our geophysical analyses suggest the Chilean Ministry of Energy approved that we will be the sole participant with a working interest of 100%. See “-Otway and Tranquilo Blocks.” additional development potential in known fields and exploration potential in undrilled prospects and plays, including opportunities in the Springhill, (5) LGI has a 14% direct equity interest in our Tierra del Fuego operations Tertiary, Tobífera and Estratos con Favrella formations. The Springhill through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for a formation has historically been the source of production in the Fell Block, total effective equity interest of 31.2% in our Tierra del Fuego operations. though the Estratos con Favrella shale formation is the principal source See “-Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)” rock of the Magallanes Basin, and we believe it contains unconventional and “-Significant agreements-Agreements with LGI-LGI Chile Shareholders’ resource potential. Agreements.” (6) At December 31, 2013, the Consortium members and interest were: GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. Fell Block In 2006, we became the operator and 100% interest owner of the Fell Block. During 2014 Methanex and Wintershall announced their decision to exit the When we first acquired an interest in the Fell Block in 2002, it had no material Consortium. The new ownership is GeoPark 50% and Pluspetrol 50%. oil and gas production. Since then, we have completed more than 1,100 sq. km of 3D seismic surveys and drilled 95 exploration and development wells. In the year ended December 31, 2014, we produced an average of approximately 5,580 boepd, in the Fell Block, consisting of 61% oil. 76 GeoPark 20F The Fell Block has an area of approximately 368,000 gross acres in the oil window for this play. We have begun work to reinterpret core (1,488 sq. km) and its center is located approximately 140 km northeast of data logs and well test information, evaluate cores and fluids and determine the city of Punta Arenas. It is bordered on the north by the international reservoir brittleness (for fracturing) through special field tests. border between Argentina and Chile and on the south by the Magellan Strait. The first exploration efforts began on the Fell Block in the 1950s. Through Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks) In the first and second quarters of 2012, we entered into three CEOPs 2005, ENAP carried out seismic surveys and drilled numerous wells in the with ENAP and Chile granting us working interests in the Isla Norte, Block. From 2006 through August 2011, we invested approximately Campanario and Flamenco Blocks, located in the center-north of the Tierra US$210 million in exploring and developing the Fell Block, which allowed del Fuego province of Chile. We are the operator of all three of these blocks, us to transition approximately 84% of the Fell Block’s area from an with working interests of 60%, 50% and 50%, respectively. We believe that exploration phase into an exploitation phase, which we expect will last these three blocks, which collectively cover 463,700 gross acres through 2032. During the exploration phase, we exceeded the minimum (1,877 sq. km) and are geologically contiguous to the Fell Block, represent work and investment commitment required under the Fell Block CEOP strategic acreage with resource potential. Following the successful by more than 75 times, and as of December 31, 2014, had invested more methodology we employed on the Fell Block, we expect to evaluate early than US$510 million in the Fell Block. There are no minimum work and production opportunities from existing nonproducing wells in Tierra del investment commitments under the Fell Block CEOP associated with the Fuego. We have committed to paying 100% of the required minimum exploitation phase. investment under the CEOPs covering these blocks, in an aggregate amount of US$101.4 million through the end of the first exploratory periods for these Geologically, the Fell Block is located in the north-eastern part of blocks, which we expect will occur by November 2015 for the Flamenco the Magallanes Basin. The principal producing reservoir is composed by and Isla Norte Blocks and by January 2016 for the Campanario Block, which sandstones in the Springhill formation, at depths of 2,200 to 3,500 meters. includes our covering of ENAP’s investment commitment which corresponds Additional reservoirs have been discovered and put into production in to its working interest in the blocks. In the first quarter of 2012, we began the Fell Block-namely, Tobífera formation volcaniclastic rocks at depths 3D seismic operations in the Flamenco Block. As of March 2015, 16 wells of 2,900 to 3,600 meters, and Upper Tertiary and Upper Cretaceous have been drilled (for a total investment commitment of 21 wells) sandstones, at depths of 700 to 2,000 meters. and 1,500 sq. km of 3D seismic have been carried out over the three blocks; which represent the total 3D seismic program commitment. Our geosciences team continues to identify and develop an attractive inventory of prospects and drilling opportunities for both exploration and Exploration in the Tierra del Fuego province in the Magallanes Basin dates development in the Fell Block, and we expect to continue our comprehensive back to the 1940s, when the first surface exploration focused on obtaining drilling program in the Fell Block in the coming years. The previous oil stratigraphic and structural information. Structural traps with transgressive discoveries in the Konawentru, Yagán, Yagán Norte, Copihue and Guanaco sandstone reservoirs (Springhill formation) were outlined with refraction fields have opened up new oil and gas potential in the Fell Block. An important discovery during 2011 was the Konawentru 1 well, which we seismic lines and, in 1945, oil was discovered. initially tested to have in excess of 2,000 bopd from the Tobífera formation, In the specific area of our Tierra del Fuego Blocks, the first wells were drilled and which has opened up additional potentially attractive opportunities in 1951, resulting in the discovery of the Sombrero oil and gas field. At the (workovers, well-deepening’s and new exploration and development wells) end of the 1950s and in the early 1960s, new fields were discovered to the in the Tobífera formation throughout the Fell Block. east (the Catalina and Cuarto Chorrillo fields) and, following the gathering of During the last three months of 2012, and throughout 2013 and 2014, we existing fields were further developed. During the past decade, geological continued our exploration and development from the Tobífera formation by studies in the Magallanes Basin have focused on stratigraphic analysis, based drilling wells in Konawentru, Yagán and Yagán Norte fields, as well as on 3D and 2D seismic information, the definition and distribution of facies deepening existing wells in Ovejero and Molino. Exploration efforts in 2014 of the deltaic and/or turbidite depositional systems of the Late Cretaceous- resulted in the discoveries of the Ache gas field and the Loij oil field. Our team Tertiary period and the evolution of the oil system in terms of is working on identifying other Tobifera wells where to replicate these results. generation/timing/expulsion and trapping. seismic reflection data acquisition, additional new fields were discovered and We also continue to evaluate the Estratos con Favrella shale reservoir, which Geologically, our Tierra del Fuego Blocks are located in the south-eastern we believe represents a high-potential, unconventional resource play for margin of the Magallanes Basin. The principal producing reservoir is shale oil and gas, as a broad area of the Fell Block (1,000 sq. km) appears to be composed by sandstones in the Springhill formation at depths of 1,800 to GeoPark 20F 77 2,300 meters. Additional reservoirs have been discovered and put into In the Otway Block, as of December 31, 2013, we had a 25% working interest production in the Tierra del Fuego Blocks namely Tobífera formation and our partners were Pluspetrol (25%), Wintershall (25%), IFC (12.5%) and volcaniclastic rocks at depths of 2,000 to 2,500 meters, and Upper Terciary Methanex (12.5%). Our partners withdrew from the joint operating and Upper Cretaceous sandstones, at depths of 500 to 1,400 meters. agreement governing the Otway Block in May 2013, and applied to the Isla Norte Block. We are the operator of, and have a 60% working interest in partnership with ENAP in the Isla Norte Block, which covers approximately 130,200 gross acres (527 sq. km). As of March 2015 we had completed Chilean Ministry of Energy to assign their rights to us in the Otway Block CEOP in August 2013. In September 2014, the Chilean Ministry of Energy approved that we will be the sole participant with a working interest of 100%. 100% of the committed 350 sq. km of 3D seismic surveys. We have also In 2012, we drilled two wells in the Otway Block, both of which were committed to drilling three wells during the first exploration period under subsequently plugged and abandoned. the CEOP governing the Isla Norte Block. Pantano Oeste 1 well marks the first oil discovery on the Isla Norte Block. As of the date of this annual report, On April 10, 2013, we voluntarily and formally announced to the Chilean outstanding investment commitments related to this Block corresponds Ministry of Energy our decision not to proceed with the second exploratory to 2 exploratory wells until November 2015 for approximately US$6.5 period and to terminate the exploratory phase under the Otway Block CEOP, million. In the year ended December 31, 2014, we produced an average of such that we relinquished all areas of the Otway Block, except for two areas approximately 41.4 boepd, in the Isla Norte Block. totaling 49,421 gross acres in which we declared the discovery of Campanario Block. We are the operator of, and have a 50% working interest in, the Campanario Block, in partnership with ENAP. The Block covers In the Tranquilo Block, as of December 31, 2014, we had a 29% working approximately 192,200 gross acres (778 sq. km). As of March 31, 2015, we had interest, where our partners were Pluspetrol (29%), Wintershall (25%) and completed 100% of the committed 578 sq. km of 3D seismic surveys. We Methanex (17%). During 2014 Methanex and Wintershall announced their have also committed to drilling eight wells during the first exploration period decision to exit the Consortium. The new ownership is GeoPark 50% and hydrocarbons, in the Cabo Negro and Tatiana prospect areas. under the CEOP governing the Campanario Block. During 2014 we drilled Pluspetrol 50%. 5 exploratory wells, including the Primavera Sur 1 well that marks the first discovery of an oil field on the Campanario Block in addition to one In the Tranquilo Block we completed a seismic program consisting of development well. As of the date of this annual report, outstanding 163 sq. km of 3D seismic and 371 sq. km of 2D seismic survey work, and investment commitments related to this Block correspond to 3 exploratory drilled four wells, including the Palos Quemados and Marcou Sur well. wells until January 2016 for approximately US$11.9 million. In the year The Marcou Sur well is under evaluation and we discovered gas in the ended December 31, 2014, we produced an average of approximately El Salto formation of the Palos Quemado well. At the Palos Quemados well, 13.3 boepd, in the Campanario Block. we completed a 22-week commercial feasibility test aimed at defining its productive potential. As the test was not conclusive, we were granted Flamenco Block. We are the operator of, and have a 50% working interest in, the Flamenco Block, in partnership with ENAP. The Block covers permission by the Chilean Ministry of Energy to extend the testing period for an additional six months. Upon such testing period, GeoPark kept approximately 141,300 gross acres (582 sq. km). In June 2013, we discovered 4 provisional protection areas, which enable continued analysis of the area a new oil and gas field in the Block following the successful testing of the prior the declaration of its commercial viability for a period of 5 years. On Chercán 1 well, the first well drilled by us in Tierra del Fuego. As of March 31, January 17, 2013, we formally announced to the Chilean Ministry of Energy 2015, we had completed 100% of the committed 570 sq. km of 3D seismic our decision not to proceed with the second exploratory period and to surveys. We have also committed to drilling ten wells during the first terminate the exploratory phase of the Tranquilo Block CEOP. Subsequently, exploration period under the CEOP governing the Flamenco Block. During we relinquished all areas of the Tranquilo Block, except for a remaining 2014 we drilled 6 exploratory wells and 2 development wells. As of the area of 92,417 gross acres, for the exploitation of the Renoval, Marcou Sur, date of this annual report, there are no outstanding investment commitments Estancia Maria Antonieta and Palos Quemados Fields, which we have related to this Block as we have completed 100% of 3D seismic surveys and identified as the areas with the most potential for prospects in the Block. 10 exploratory wells. In the year ended December 31, 2014, we produced an average of approximately 199.1 boepd in the Flamenco Block. As of December 31, 2013, we had completed our minimum work Otway and Tranquilo Blocks We are the operator of the Otway and Tranquilo Blocks. commitments 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 commitment program was completed in 2011 and included 270 sq. km of 3D seismic and 127 km of 2D seismic survey work. 78 GeoPark 20F Operations in Colombia In the first quarter of 2012, we acquired Winchester, Luna and Cuerva, Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant three privately-held E&P companies operating in Colombia. We closed to an E&P Contract with the ANH, whereas “economic interests” are the acquisitions of Winchester and Luna in February 2012 and the acquisition indirect participation interests in the net revenues from a given block based of Cuerva in March 2012. We acquired Winchester, Luna and Cuerva for on bilateral agreements with the concessionaires. a total consideration of US$105.0 million, adjusted for working capital. Additionally, in December 2012, LGI agreed to acquire a 20% equity interest The map below shows the location of the blocks in Colombia in which we in GeoPark Colombia for a total consideration of US$20.1 million, composed have working and/or economic interests. of a US$14.9 million capital contribution, a US$4.9 million loan to GeoPark Colombia and certain miscellaneous reimbursements. See “-Significant agreements-Agreements with LGI-LGI Colombia Agreements.” C A R I B B E A N S E A On July 23, 2014 we were awarded a new exploratory license, during the P A N A M A 2014 Colombia Bidding Round, carried out by the ANH for the VIM -3 Block. We believe 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. In November 2014, we further expanded our portfolio in Colombia through an agreement with SK Innovation (a subsidiary of SK Group, the Korean integrated energy and petrochemical company) to farm-in to the CPO-4 Block, located in the Llanos Basin. We and SK have jointly identified new prospects in this Block similar to prospects and leads in our Llanos 34 Block. P A C I F I C O C E A N Abanico VIM-3 Cerrito Llanos 17 Yamu V E N E Z U E L A Jagüeyes La Cuerva Llanos 62 Llanos 32 Llanos 34 CPO-4(1) C O L O M B I A Our Colombian assets currently give us access to 1,068.7 of gross exploratory and productive acres across 11 blocks in what we believe to be one of South America’s most attractive oil and gas geographies. Since we acquired Winchester, Luna and Cuerva, we were able to perform an active exploration and development drilling campaign, which resulted in multiple new discoveries and to increase average production to 11,615 boepd in Colombia in the fourth quarter of 2014. E C U A D O R P E R U B R A Z I L According to the D&M Reserves Report, as of December 31, 2014, the blocks (1) Subject to the approval of ANH. in Colombia in which we have a working interest had 24.7 mmboe of net proved reserves, all of which were in oil. Under the terms of the agreement to acquire Winchester, or the Winchester Stock Purchase Agreement, we are obligated to make certain payments to the 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 2014, we paid US$21.0 million and accrued US$24.6 million to the previous owners of Winchester pursuant to the Winchester Stock Purchase Agreement. GeoPark 20F 79 The table summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2014 Block La Cuerva Llanos 34 Llanos 62 Yamú Llanos 17 Llanos 32 Gross acres (thousand acres) Working interest(1) Net proved reserves Production Partners(2) Operator (mmboe)(3) (boepd) Basin Concession expiration year Exploration: 2014 47.8 100.0% - GeoPark 2.6 1,389 Llanos Exploitation: 2038 82.2 45.0% Parex GeoPark 21.5 8,306 Llanos Exploitation: 2039 Exploration: 2015 44.0 100.0% 11.2 79.5/ 90%(4) 108.8 36.8%(5) - - GeoPark GeoPark - 0.5 - Llanos 388 Llanos Exploration: 2017 Exploitation: 2041 Exploration: 2013(6) Production: 2036 Exploration: 2015 Parex Parex 0.03 52 Llanos Exploitation: 2039 Exploration: 2015 100.3 10% APCO; Parex Parex 0.1 486 Llanos Exploitation: 2039 Jagu(cid:0) eyes 3432A 61.0 5.0% Columbus Columbus VIM-3 CPO-4(7) 225.0 100% - GeoPark 345.6 50% SK GeoPark - - - - Llanos Exploitation: 2038 Exploration: 2014 - Magdalena Exploitation: 2045 Exploration: 2021 Exploration: 2015 - Llanos Exploitation: 2038 (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 through GeoPark Colombia. See “-Significant agreements-Agreements with LGI-LGI Colombia Agreements.” (2) Partners with working interests. (3) As of December 31, 2014. (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 79.5% interest in the Carupana Field and a 90% interest in the Yamú and Potrillo Fields, both located in the Yamú Block. (5) We currently have a 40% working interest in the Llanos 17 Block, although we assigned a 3.2% economic interest to a third party. We expect to formalize this assignment with the ANH so that it will be recognized as a working interest. (6) The Yamú Block E&P Contract is in both the exploration and exploitation phases. The phases overlap because the exploitation phase (lasting 24 years) for the Yamú and Carupana Fields began on the date these fields were declared commercially viable, while the exploration phase continued to run for the rest of the Block. (7) Subject to regulatory approval from the ANH in Colombia. 80 GeoPark 20F The table summarizes information about the blocks in Colombia in which three-way dip closure on the down-thrown side of a normal fault – targeting we have economic interests as of and for the year ended December 31, 2014. the two principal productive reservoirs, the Guadalupe (main target) and Gross acres (thousand acres) 32.1 10.2 Economic interest(1) 10% 10% Block Abanico Cerrito Mirador (secondary target) sandstones. We drilled and completed the Tilo 1 exploratory well to a total depth of 11,293 feet. A test conducted with Production an electrical submersible pump in the Guadalupe formation, at approximately Operator (boepd) Basin 10,707 feet, resulted in a production rate of approximately 1,000 bopd of Pacific Pacific 83 Magdalena 14.2 degree API, with approximately 10% water cut. On March 28, 2015 Tilo 1 - Catatumbo commenced a long-term test and current production is approximately 850 bopd. Further production history is required to determine stabilized flow (1) Economic interest corresponds to indirect participation interests in rates of the well and the extent of the field. Further technical evaluation the net revenues from the Block, granted to us pursuant to a joint operating will also be undertaken to determine if the Tilo field is potentially a northeast agreement. extension of the larger Tigana field. Eastern Llanos Basin: (La Cuerva, Yamú, Llanos 34, Llanos 32, Llanos 62, For 2015, we expect to focus on facilities optimization and plan to drill up Llanos 17, Jagu(cid:0) eyes 3432A, Abanico, Cerrito, CPO-4 and VIM-3 Blocks) The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region to 4 development wells in Tua and Tigana oil fields, depending on oil prices. of Colombia. Two giant fields (Caño Limón and Castilla), three major Our partner in the Llanos 34 Block is Parex, which has a 55% interest. fields (Rubiales, Apiay and Tame Complex) and approximately fifty minor See “-Our operations.” We operate in the Block pursuant to an E&P Contract fields had been discovered. The source rock for the basin is located beneath with the ANH. See “-Significant agreements-Colombia-E&P Contracts- the east flank of the Eastern Cordillera, as a mixed marine-continental shaly Llanos 34 Block E&P Contract.” basinal facies of the Gachetá formation. The main reservoirs of the basin are represented by the Paleogene Carbonera and Mirador sandstones. Within the Cretaceous sequence, several sandstones are also considered to have good reservoirs. Llanos 34 Block. We are the operator of, and have a 45% working interest in, the Llanos 34 Block, which covers approximately 82,200 gross acres La Cuerva Block. We are the operator of, and have a 100% working interest in, the La Cuerva Block, which covers approximately 47,800 gross acres (190 sq. km). Since we acquired an interest in the La Cuerva Block, we have drilled a total of 15 wells in the Block, 17 of which were productive at year-end 2014. For the year ended December 31, 2014, our average net production at the La Cuerva Block was 1,389 bopd. We operate in the Block (333 sq. km). We acquired an interest in and took operatorship of the Block pursuant to an E&P Contract with the ANH. In the first quarter 2015, the in the first quarter of 2012, which at the time had no production, reserves block was temporarily shut down. See “-Significant agreements-Colombia- or wells drilled on it, and with 210 sq. km of existing 3D seismic on which our E&P Contracts-La Cuerva Block E&P Contract.” team had mapped multiple exploration prospects. During 2012, we drilled the Tua prospect and made a discovery in the Guadalupe and Mirador reservoirs. Two additional follow up wells were successfully drilled and placed Llanos 62 Block. We are the operator of, and have a 100% working interest in, the Llanos 62 Block, which covers approximately 44,000 gross acres on production at Tua, and a water disposal well was drilled at Max field. In (178 sq. km). As of December 31, 2014, we had undertaken 72.2sq. km of 2013, an additional three delineation wells were drilled at Tua, which 3D seismic surveys within the Block. We operate the Block pursuant to an E&P were all placed on production, and also the Tigana and Tarotaro fields were Contract with the ANH. We have committed to drill two exploratory wells discovered in 2013, for a total of four wells in Tarotaro and two wells in before July 2015. The remaining commitment amounts to US$6.0 million. the Tigana Field. Both fields are productive in the Guadalupe and Mirador reservoirs and produce oil of 15º to 20º API. In 2014, we focused on the development of Tua and the delineation and development of the Tigana Yamú Block. We are the operator of, and have a 100% working interest in, the Yamú Block, which covers approximately 11,200 gross acres (45.5 sq. km). Field. In 2014, we drilled 6 additional wells in the Tigana Field, 5 of which Economic rights to certain fields in the Yamú Block have been granted to are in production. Furthermore, an additional 5 wells were drilled at Tua, 4 of other parties. In May 2013, we successfully drilled and completed the Potrillo which are in production, and 1 well, Tua 10, is to be tested. Average net oil 1 well in the Block to a total depth of 3,560 meters. The well was put in production from Llanos 34 Block in 2014 was 8,306 bopd. production with an initial rate of 744 bopd and a water cut of 15%. The well has been producing from the existing facility at Carupana Field. For the year In February 2015, we announced a new oil field discovery following the ended December 31, 2014, our average net production at the Yamú Block was drilling of exploration well Tilo 1 on the Llanos 34 Block. This is the sixth 388 bopd. We operate in the Block pursuant to an E&P Contract with the ANH. discovery in this block. The Tilo prospect was defined as a structural trap with On July 29, 2014, our Colombian subsidiary agreed to exchange its 10% non- GeoPark 20F 81 operating economic interest in the Arrendajo Block for additional interests rather had a 10% economic interest in the net revenues of the Arrendajo held by the seller in the Yamú Block that includes a 15% economic interest Block pursuant to a participating interest agreement between us and Great in all of the Yamú fields except for the Carupana field, where the seller North Energy Colombia Inc. (now Pacific). had a 25% economic interest. We received US$3.2 million in cash from the exchange, adjusted for working capital. In the first quarter 2015 we temporarily shut down our operations in this Block. Llanos 17 Block. We have a 40% working interest in the Llanos 17 Block, which covers approximately 108,800 gross acres (440 sq. km). Parex is the Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Pacific is the operator of, and has a 100% working interest in, the Abanico Block, which covers an area of approximately 32.1 gross acres. We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic operator of, and has a 60% working interest in, the Llanos 17 Block. Since we interest in the net revenues from the Block pursuant to a joint operating acquired a working interest in the Block, two wells have been drilled in the agreement initially entered into with Kappa Resources Colombia Limited Block, one of which was productive. We maintain our 40% working interest (now Pacific, who subsequently assigned its participation interest to in the Llanos 17 Block pursuant to an E&P Contract with the ANH. However, Cespa de Colombia S.A., who then assigned the interest to Explotaciones we expect to apply to the ANH to approve an assignment of 3.2% of our CMS Oil & Gas), Maral Finance Corporation and Getionar S.A. working interest in this Block to another party. For the Llanos 17 Block, there is still a remaining commitment that amounts to US$4.3 million (US$1.6 million of our working interest), which is expected to be completed with an additional exploratory well. Llanos 32 Block. We have a 10% working interest in the Llanos 32 Block, which covers approximately 100,300 gross acres (406 sq. km) Parex is the Cerrito Block. In February of 2002, Ecopetrol and Kappa Resources Colombia Limited (now Pacific) entered into the Cerrito Block association contract. The Cerrito Block covers an area of approximately 10.2 thousand gross acres. Pacific is the operator of, and has a 100% working interest in, the Cerrito Block. We do not maintain a direct working interest in the Cerrito Block, but rather have a 10% economic interest in the Block pursuant to a joint operator of, and has a 70% working interest in, the Llanos 32 Block. Parex’s operating agreement initially entered into with Kappa Resources Colombia other partner in the Block is APCO Properties Ltd., or APCO, who has a Limited (now Pacific), Maral Finance Corporation, Geoproduction Oil & Gas 20% working interest. Since we acquired an interest in the Llanos 32 Block, Company of Colombia Limitada and Texican Oil PLC. and as of December 31, 2013, five wells have been drilled in the Block, three of which were productive. In 2014, three additional discoveries were made at fields Kananaskis, Carmentea and Calona in both the Mirador VIM-3 Block. On July 23, 2014 we were awarded a new exploratory license during the 2014 Colombia Bidding Round, carried out by the ANH. The and Une reservoirs, with 7 wells drilled: 4 wells in Kananaskis, 1 well in Calona, VIM-3 Block is located in the Lower Magdalena Basin, covering an area and 2 wells at Carmentea. For the year ended December 31, 2014, our of approximately 225,000 acres. GeoPark’s winning bid consisted of average net production in the Llanos 32 Block was 486 bopd. committing to a Royalty X Factor of 3% and a minimum investment program Jagu(cid:0) eyes 3432A Block. We have a 5% working interest in the Jagu(cid:0) eyes 3432A Block, which covers approximately 61,000 acres (247 sq. km). Our partner in with a total estimated investment of US$22.2 million during the initial three year exploratory period. GeoPark will operate and have a 100% working the Block is Columbus Energy, who maintains a 95% working interest in and is interest in the Block. We believe the Block has an attractive oil and gas the operator of the Jagu(cid:0) eyes 3432A Block. We maintain a working interest in exploration potential in a large area within a proven hydrocarbon system, the Jagu(cid:0) eyes 3432A Block pursuant to an E&P Contract with the ANH. surrounded by existing oil and gas fields and with sparse exploration of carrying out 200 sq km of 2D seismic and drilling one exploratory well, activity carried out to date. Arrendajo Block. In December 2005, Great North Energy Colombia Inc. (now Pacific Stratus Energy Corp., or Pacific) and the ANH entered into the Arrendajo Block E&P Contract. Pacific is the operator of, and has a 100% CPO-4 Block. In November 2014, we expanded our portfolio in Colombia through an agreement with SK Innovation (subsidiary of SK Group, the Korean working interest in, the Arrendajo Block, which covers approximately 78.1 integrated energy and petrochemical company) to farm-in to the CPO-4 gross acres. On July 29, 2014, our Colombian subsidiary agreed to exchange Block, located in the Llanos Basin. The Block covers an area of approximately its 10% non-operating economic interest in the Arrendajo Block for additional 345,600 acres with 3D seismic coverage of approximately 880 sq km. In interests held by the seller in the Yamú Block that includes a 15% economic accordance with the farm-in agreement, and subject to the approval of ANH interest in all of the Yamú fields except for the Carupana field, where the in Colombia, we will operate and receive a 50% working interest in the CPO-4 seller had a 25% economic interest. We received US$3.2 million in cash from Block in exchange for its commitment to drill and fund its 50% (with no carry) the exchange, adjusted for working capital. We did not maintain a direct of one exploration well. The well is targeted for 1H2015 and our total financial working interest in this Block pursuant to an E&P Contract with the ANH, but commitment is approximately $6.0 million. There is an option to move to an 82 GeoPark 20F additional exploration phase following the drilling of a successful well. Final not in default as long as the regulator does not state its final position on the approval from the ANH is expected in the first half of 2015. renewal. See “-Health, safety and environmental matters-Other regulation of Operations in Brazil On May 14, 2013, we announced the future extension of our footprint into the oil and gas industry-Brazil.” The Camarão Norte Field is in the development phase and is not yet subject to the environmental licensing requirement. Brazil when the ANP awarded us seven new exploratory licenses in the Our acquisition of Rio das Contas in Brazil, which closed on March 31, 2014, REC-T 94 and REC-T 85 Concessions in the Recôncavo Basin in the State of provides us with a long-term off-take contract with Petrobras that covers Bahia and the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 approximately 74% of net proved gas reserves in the Manatí Field, a valuable Concessions in the Potiguar Basin in the State of Rio Grande do Norte, relationship with Petrobras and an established local platform and presence, or our Round 11 concessions, collectively covering an area of approximately with seasoned and experienced geoscience and administrative team to 54,900 gross acres. On September 17, 2013, we entered into seven manage the assets and to seek new growth opportunities. concession agreements with the ANP for the right to exploit the oil and natural gas in these seven new concessions. For our winning bids on these In January 31, 2015 Rio das Contas was merged into GeoPark Brazil seven concessions, we committed to invest a minimum of US$15.3 million Exploração e Produção de Petróleo e Gás Ltda, being the only entity (including bonuses and estimated work program commitment) during representing GeoPark in Brazil. the first three years of the exploratory period for the concessions. We have already invested US$5.4 million in seismic work and US$4.4 million in We are currently qualified us as a class B operator, meaning that we are bonuses paid to ANP as of the date of this annual report. recognized as having met all technical and managerial conditions required to operate safely in Brazil, both onshore and offshore at water depths of These seven new concessions cover an area of approximately 54,850 gross less than 400 meters. acres. Pursuant to ANP requirements, actual exploitation of these new concessions will also depend on obtaining an environmental license from The map below shows the location of the concessions in Brazil in which we the respective state environmental agencies. expect to have working interests as a result of our Brazil Acquisitions. Also in Brazil, on November 28, 2013, the ANP awarded us two new concessions, the PN-T-597 Concession in the Parnaíba Basin in the State of Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin in the State of Alagoas, in the 12th oil and gas bidding round. The PN-T-597 Concession is still subject to the entry into the concession agreement. For our winning bids on these two concessions, we have committed to invest a minimum of US$4.0 million (including bonus and estimated work program commitments) during the first exploratory period. These two new concessions cover an area of approximately 196,500 acres. For more information, see B R A Z I L “-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.” POT-T-620 POT-T-619 POT-T-663 POT-T-664 PN-T-597(1) POT-T-665 REC -T- 85 REC -T- 94 BCAM-40 (Manati) SEAL-T-268 Additionally, we acquired Rio das Contas from Panoro for a total cash consideration of US$140 million and gives us a 10% working interest in the BCAM-40 Concession, including the shallow-depth offshore Manatí and Camarão Norte Fields, in the Camamu-Almada Basin in the State of Bahia. The Manatí Field, which is in the production phase, is operated by Petrobras (with a 35% working interest), the Brazilian national company and the largest P A R A G U A Y oil and gas operator in Brazil, in partnership with QGEP (with a 45% working interest), and Brasoil (with a 10% working interest). See “-Significant A R G E N T I N A agreements-Brazil-Rio das Contas Quota Purchase Agreement.” Some (1) The PN-T-597 Block is subject to an injunction and our bid for the environmental licenses related to operation of the Manatí Field production concession has been suspended. See “-Item 3. Key Information-D. Risk factors- system and natural gas pipeline are expired. However, the operator submitted, Risks relating to our business-The PN-T-597concession is subject to an timely, the request for renewal of those licenses and as such this operation is injunction and may not close.” GeoPark 20F 83 The following table sets forth information as of December 31, 2014 on our concessions in Brazil in which we have a current or future working interest, including the BCAM-40 Concession as well as the Round 11 and the Round 12 concessions. 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 BCAM-40 Total Brazil 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 7.9 100% 100% 100% 100% 100% 100% - - - - - - GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark 7.9 188.7 100% 100%(5) - -(5) GeoPark GeoPark 7.8 100% - GeoPark Petrobras; QGEP; Brasoil 10% Petrobras 22.8 251.4 - - - - - - - - - - Recôncavo Exploitation: 2045 - Recôncavo Exploitation: 2045 Exploration: 2018 - - - - - - - Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Potiguar Parnaíba Sergipe Alagoas Camamu- Almada Exploration: 2018 Exploitation: 2045 -(4) -(4) Exploitation: 2029(2) - 2034(3) 6.9 6.9 2,668(6) 2,668 (1) Working interest corresponds to the working interests held by our respective subsidiaries, net of any working interests held by other parties in Annual Report, confirmation remains subject to final signing and local authority approval. See “-Item 3. Key Information-Risk factors-Risks relating such concession, and including the working interest we expect to hold in PN- to our business-The PN-T-597 concession is subject to an injunction and may T-597 which as of the date of this report is pending approval. See “-Item 3. not close.” Key Information-Risk factors-Risks relating to our business-The PN-T-597 (5) We expect to jointly develop this concession with Tecpetrol and assign concession is subject to an injunction and may not close.” a portion of our working interest in this concession to Tecpetrol. See (2) Corresponds to Manatí Field. (3) Corresponds to Camarão Norte Field. Item 3-Risk Factors “The PN-T-597 concession is subject to an injunction and may not close.” (4) PN-T-597 Block subject to the entry into the concession agreement by the (6) Considering production since the acquisition date, March 31, 2014. Full ANP and absence of any legal impediments to signing. As of the date of this year 2014 production amounted to 3,572 boepd (composed of 98% gas). 84 GeoPark 20F BCAM-40 Concession As a result of the Rio das Contas acquisition, we have a 10% working interest exploratory period under the concession agreement governing the concessions, consisting of a R$7.2 million (approximately US$2.2 million, at in the BCAM-40 Concession, which includes interests in the Manatí Field the March 31, 2015 exchange rate of R$3.2080 to US$1.00) bonus payable and the Camarão Norte Field, and which is located in the Camamu-Almada to the ANP in the first year of exploration and R$12.1 million (approximately Basin. Petrobras is the operator, and has a 35% working interest in, the BCAM- US$3.8 million, at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) 40 Concession, which covers approximately 22,784 gross acres (92.2 sq. km). as a work program guarantee payable over the course of the three years. In addition to us, Petrobras’ partners in the Block are Brasoil and QGEP, The work program consists on drilling two exploratory wells and 31 sq. km of with 10% and 45% working interests, respectively. Petrobras operates the 3D seismic surveys in the REC-T94 Concession and 30 sq. km of 2D seismic BCAM-40 Concession pursuant to a concession agreement with the ANP, surveys in REC-T 85 Concession. The exploratory phase for these concessions executed on August 6, 1998. See “-Significant agreements-Brazil-Overview of is divided into two exploratory periods, the first of which lasts for three years concession agreements-BCAM-40 Concession Agreement.” In September 2009, and the second of which is non-obligatory and can last for up to two years. Petrobras announced the relinquishment of BCAM-40’s exploration area within the concession to the ANP, except for the Manatí Field and the During the year 2014 we executed a 3D seismic survey acquisition. Seismic Camarão Norte Field. data processing was concluded in the first quarter of 2015. After ANP approval, this seismic acquisition will fulfill the work program commitments for the The Manatí Field is located 65 km south of Salvador, at a 35 meter water depth. Block REC-T 85 and part of the REC-T 94. The field was discovered in October 2000, and, in 2002, Petrobras declared the field commercially viable. Production began in January 2007. As of September 30, 2013, 11 wells had been drilled in the Manatí Field, six of which POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions The POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions are productive and connected to a fixed production platform installed at a are onshore and located in the Potiguar Basin. As of December 31, 2014, depth of 35 meters, located 9 km from the coast of the State of Bahia. From according to the ANP, with 94 fields in production and 9 fields in development the platform, the gas flows by sea and land through a 125 km pipeline to the stage including onshore and offshore in the Potiguar basin. Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to Petrobras up to a maximum volume as determined in the existing Petrobras The POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 Concessions Gas Sales Agreement (as defined below). GeoPark Brazil is currently negotiating cover a total area of 39,507 gross acres (160 sq. km). The concession an amendment to the existing Gas Sales Agreement with Petrobras for the agreements require us make total investments of R$11.3 million (approximately sale of additional volumes from the Manatí Field. US$3.5 million at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) REC-T 94 and REC-T 85 Concessions The REC-T 94 and REC-T 85 Concessions are onshore and located in the during the first exploratory period under the concession agreement, with a R$3.0 million (approximately US$0.9 million at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) bonus payable to the ANP in the first year of Recôncavo Basin, which covers an area of approximately 2.7 million gross exploration and R$8.3 million (approximately US$2.6 million at the March 31, acres (11,000 sq. km). The basin’s main source rocks belong to the Candeias formation, with reservoirs on the fluvio-deltaic sandstones of the Marfim and 2015 exchange rate of R$3.2080 to US$1.00) as a work program guarantee payable over the course of the three years. We have also committed to Pojuca formations, Fluvial sandstones of the Candeias and Marancagalha undertaking 222 km of 2D seismic work in the first exploration period for the formations, and the Fluvio-Eolic sandstones of the Agua Grande and Sergi concession areas, with no well drilling commitment during this period. formations. Reconcavo basin is considered a mature basin. According to The exploratory phase for these concessions is divided into two exploratory the ANP, as of December 31, 2014, 92 fields are in production or development periods, the first of which lasts for three years and the second of which is stage in the Reconcavo basin. non-obligatory and can last for up to two years. The REC-T 94 and REC-T 85 Concessions cover an area of 7,660 gross acres During the year 2014 we executed a 3D seismic survey acquisition. Seismic data (31 sq. km) and 7,660 gross acres (31 sq. km), respectively. In connection with processing was concluded in the first quarter of 2015. After ANP approval, this our bid to obtain the licenses for these concessions, we have committed to seismic acquisition will fulfill the work program commitments for the blocks. drilling two exploratory wells in the concessions, and to undertaking 31 sq. km of 3D seismic surveys in the REC-T 94 Concession and 30 km of 2D seismic surveys in the REC-T 85 Concession. We have also committed, following the Round 12 Concessions Additionally, on November 28, 2013, the ANP awarded us two new concessions signing of the concession agreement in respect of the concessions, to a (the PN-T-597 Concession in the Parnaíba Basin in the State of Maranhão and work program to the ANP of R$19.3 million (approximately US$6.0 million, at the SEAL-T-268 Concession in the Sergipe Alagoas Basin in the State of Alagoas) the March 31, 2015 exchange rate of R$3.2080 to US$1.00) during the first in the 12th oil and gas bidding round. We have committed to invest a minimum GeoPark 20F 85 of US$4 million (including bonus and work program commitments). For more information, see “-Item 3. Key information-D. Risk factors-Risks relating SEAL-T-268 Concession The SEAL-T-268 Concession is located onshore in the Sergipe-Alagoas Basin. to our business-The PN-T-597 concession is subject to an injunction and may This basin encompasses an area of approximately 10.9 million gross acres not close.” (44,400 sq. km), of which 3.1 million gross acres (12600 sq. km) are situated onshore. It has gone through 3 main tectonic stages: pre-rift, rift, and drift. PN-T-597 Concession The PN-T-597 Concession is located onshore in the Parnaiba Basin, which covers Source rock intervals were identified on the Rift (Barra de Ituba and Coqueiro Seco Fms) and Prerift sequences (Aracare Fm). Reservoirs are the fluvio-deltaic an area of approximately 148 million gross acres (600,000 sq. km). The basin’s and lacustrine sandstones present in the pre-rift and rift intervals (Aracare, main petroleum system consists of the Devonian Pimenteras Fm source rock Serraria, Penedo and Maceio Fms). Over the drift sequence, turbiditic with reservoirs of continental to shallow marine sandstones of the Poti and sandstones were deposited, mainly in the offshore part of the basin and the Cabeças formations. Intrusive and extrusive magmatic rocks are interbedded cretaceous shale acts as seal. The onshore part of the basin is considered within the sedimentary column, influencing source rock maturation and mature in terms of hydrocarbon exploration. sometimes acting as seals. As of December 31, 2014 there were 46 fields either in production or Parnaiba is a basin with large underexplored areas. As December 31, 2014, development stages on the basin. the basin had three fields in production or development stage in the basin. The SEAL-T-268 Concession covers an area of 7,799 gross acres (31.6 sq. km). The PN-T-597 Concession covers an area of 188,667 gross acres (763.5 sq. km). GeoPark’s winning offer requires a commitment to the ANP of R$1.6 million The offer requires a commitment to the ANP of R$7.7 million (approximately (approximately US$0.5 million, at the March 31, 2015 exchange rate of R$3.2080 US$2.4 million, at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) to US$1.00) for the first exploratory period. This amount is comprised of for the first exploratory period. This amount is comprised of R$0.9 million R$0.14 million (approximately US$0.04 million, at the March 31, 2015 exchange (approximately US$0.3 million, at the March 31, 2015 exchange rate of rate of R$3.2080 to US$1.00) bonus payable to the ANP in the first year of R$3.2080 to US$1.00) bonus payable to the ANP in the first year of exploration exploration and R$1.5 million (approximately US$0.5 million, at the March 31, and R$6.7 million (approximately US$2.1 million, at the March 31, 2015 2015 exchange rate of R$3.2080 to US$1.00) as a work program guarantee exchange rate of R$3.2080 to US$1.00) as a work program guarantee payable payable over the course of three years. Work program is equivalent to 40 km of over the course of the four years. Work program is equivalent to 180 km of 2D 2D seismic, with no well drilling committed during the first exploratory period. seismic, with no well drilling committed during the first exploratory period. The exploratory phase for these concessions is divided into two exploratory periods, the first lasting three years, and the second, which is optional, can last The exploratory phase for this concession is divided into two exploratory periods. Given that Parnaiba basin is considered as a “new frontier” area by the for up to two years. ANP, the first exploratory period lasts four years, and the second exploratory period, which is optional, can last for up to two years. See “-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” and “-D. Risk factors-Risks relating to the countries in which we operate-Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may operate in the future” for more information. 86 GeoPark 20F Operations in Peru The table and map below summarize 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% Net proved reserves Production Expiration Operator GeoPark (mmboe)(2) 18.8 (boepd) Basin - Marañon concession year Exploitation: 2036(3) (1) Corresponds to the initial working interest. Petroperú will have the right to increase its working interest in the Block by up to 50%, subject to Morona Block The Morona Block covers an area of approximately 1,881 thousand gross the recovery of our investments in the Block through agreed terms in the acres (7,600 sq. km). More than 1 billion barrels of oil have been produced Petroperú SPA. See “-Item 4. Information on the Company-B. Business from the surrounding blocks in this basin. We have a 75% working interest in overview-Our operations-Operations in Peru-Morona Block.” the Morona Block. For the year ended December 31, 2014, net proved (2) Certified by D&M as of December 31, 2014. reserves at the Morona Block were 18.8 mmboe (composed of 100% oil). (3) The concession year expiration is related to approval of an environmental impact assessment (EIA) study for project development. The concession will On October 1, 2014, we entered into an agreement to acquire a 75% expire twenty (20) years after EIA approval. We expect the EIA to be approved working interest in the Morona Block in Northern Peru. As stated above, this around December 2016. E C U A D O R C O L O M B I A Morona (1) B R A Z I L P E R U P A C I F I C O C E A N agreement includes a work program to be executed by GeoPark. This program includes 3 phases and GeoPark may decide to continue or not at the end of each phase. 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 high impact prospects and plays. This important component of the project will significantly increase our overall inventory of exploration resources. The Morona Block includes geophysical surveys of 2,783 km (2D seismic) and 465 sq km (3D seismic), and an operating field camp and logistics infrastructure. The area has undergone oil and gas exploration activities for the past 40 years, and there exist ongoing association agreements and cooperation projects with the local communities. The expected work program and development plan for the Situche Central oil field is to be completed in three stages. The goal of the initial 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 B O L I V I A generate cash flow. This initial stage requires an investment of approximately US$140 million to US$160 million and is expected to be completed within C H I L E 18 to 24 months after closing. We have committed to carry Petroperú, by paying its portion of the required investment in this initial phase. (1) Transaction executed with Petroperú on October 1, 2014 with final closing The subsequent work program stages, which will be initiated once production subject to Peru government approval. We expect to close the pending has been established, are focused on carrying out the full development Morona Block Acquisition in 2015. of the Situche Central field, including transportation infrastructure, and new exploration drilling of the Block. GeoPark 20F 87 The exploratory program entails drilling one exploratory well. Exploratory program capital expenditures will be borne exclusively by GeoPark. Operations in Argentina The map below shows the location of the blocks in Argentina in which we have working interests as of December 31, 2014. Initially we will have a 75% working interest. However, according to the terms of the agreement, Petroperú will have the right to increase its working interest in the Block by up to 50%, subject to the recovery of our investments in the Block by certain agreed factors. In Peru, there is a 5-20% sliding scale royalty rate, depending on production levels. Production less than 5,000 bopd is assessed at a royalty rate of 5%. For production between 5,000 and 100,000 bopd there is a linear sliding scale between 5% and 20%. Production over 100,000 bopd has a flat royalty of 20%. B O L I V I A P A R A G U A Y B R A Z I L A R G E N T I N A U R U G U A Y Sierra Nevado Puelen C H I L E Del Mosquito The table below summarizes information about the blocks in Argentina in which we have working interests as of December 31, 2014. Block Del Mosquito Puelen(3) Sierra del Nevado(3) Gross acres (thousand acres) Working interest(1) Net proved reserves Production Operator (mmboe)(2) (boepd) Basin 17.3 1,430.0 305.0 100% GeoPark 18% Pluspetrol 18% Pluspetrol - - - Magallanes Austral Neuquén Neuquén 75 - - Expiration concession year Exploitation: 2016 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, 2014. (3) Blocks awarded in the 2014 Mendoza Bidding Round. 88 GeoPark 20F As of December 31, 2014, although we had production in Del Mosquito portfolio following the decision to relinquish the non-productive Cerro Doña Block in Argentina, D&M determined that there were no reserves in this Block Juana and Loma Cortaderal Blocks. due to the uneconomic status of the reserves, given the proximity to the end of the concessions for these blocks, which does not allow for future capital According to the Secretariat of Energy (Secretaría de Energía) in Argentina, investment in the blocks. Del Mosquito Block We are the operator of, and have 100% working interest in, the Del Mosquito or the Argentine Secretary of Energy, for the year ended December 31, 2014, the Neuquin Basin produced approximately 40% of Argentina’s total oil production and approximately 56% of its total gas production. Block. We established oil production in the Block in 2002 by rehabilitating the abandoned Del Mosquito Field and subsequently discovered the Del Relinquishment of the Cerro Doña Juana and Loma Cortaderal Blocks In April 2014, we informed the Secretary of Infrastructure and Energy of the Mosquito Norte field. For the year ended December 31, 2014, our average Province of Mendoza of our decision to relinquish 100% of the Cerro Doña daily production at the Del Mosquito Block was 75 boepd. Juana and Loma Cortaderal Concessions to the Mendoza Province. Neither the Cerro Doña Juana nor the Loma Cortaderal had production or associated The Del Mosquito Block covers an area of approximately 17,313 gross acres reserves at the time of the relinquishment. (70 sq. km), and is located in the Magallanes Austral Basin in southern Argentina. In the first quarter 2015 we temporarily shut down our operations Oil and natural gas reserves and production in this Block. Overview We have achieved consistent growth in oil and gas reserves from our According to the Secretariat of Energy (Secretaría de Energía) in Argentina, or investment activities since 2007, when we began production in the Fell Block. the Argentine Secretary of Energy, for the year ended December 31, 2014, As of December 31, 2014, D&M reported that our total net proved reserves the Magallanes Austral Basin produced approximately 4% of Argentina’s total in Chile, Colombia, and Brazil were 43.7 mmboe. Of this total, 12.1 mmboe or oil production and approximately 24% of its total gas production. 28%, 24.7 mmboe, or 57%, and 6.9 mmboe, or 15%, were in Chile, Colombia New Blocks awarded in the 2014 Bidding Round Mendoza (Argentina) On August 20, 2014, the consortium of GeoPark and Pluspetrol was awarded two exploration licenses in the Sierra del Nevado and Puelen Blocks, as and Brazil, respectively, and we had no net proved reserves in Argentina. The D&M Reserves Report estimates total net proved reserves for the Morona Block in Peru to be 18.8 mmboe. part of the 2014 Mendoza Bidding Round in Argentina, carried out by The following table summarizes our net proved reserves in Chile, Colombia, Empresa Mendocina de Energía S.A. (“EMESA”). The blocks cover an area of Argentina and Brazil as of December 31, 2014. approximately 1.7 million acres and are located in the Neuquén Basin, Argentina’s largest producing hydrocarbon basin. The consortium consists of Pluspetrol (operator with a 72% working interest)), EMESA (non-operator with a 10% working interest) and GeoPark (non-operator with an 18% working interest). In accordance with the terms of the bidding, all of the expenditures Country related to EMESA’s working interest will be carried by Pluspetrol and GeoPark Chile proportionately to their respective working interests, and will be recovered through EMESA’s participation in future potential production. The Puelen Block covers an area of approximately 1,430.0 thousand gross acres, and is located in the Neuquén Basin in southern Argentina. Colombia Argentina Brazil Total Total net proved Gas (bcf) 34.0 reserves (mmboe)(1) 12.1 - - 40.5 74.5 24.7 - 6.9 43.7 % Oil 53% 100% - 2% 72% Oil (mmbbl) 6.4 24.7 - 0.1 31.3 (1) We calculate one barrel of oil equivalent as six mcf of natural gas. The Sierra del Nevado Block covers an area of approximately 305.0 thousand gross acres, and is located in the Neuquén Basin in southern Argentina. We have committed to a minimum aggregate investment of US$6.2 million for this working interest, which includes the work program commitment on both blocks during the first three years of the exploratory period. In addition to forming a partnership with Pluspetrol, one of the largest Latin American independent companies, these licenses will rebalance our Argentinean GeoPark 20F 89 The following table summarizes the net proved reserves in Peru for the pending Morona Block Acquisition as of December 31, 2014, according to the D&M Reserves Report. We expect to close the pending Morona Block Acquisition in 2015. Net proved reserves As of December 31, 2014 Natural Total net proved Oil (mmbbl) gas (bcf) reserves (mmboe)(1) Total net proved reserves (mmboe)(1) 18.8 18.8 Gas (bcf) - - Oil (mmbbl) 18.8 18.8 Country Peru Total Net proved developed Peru % Oil 100% 100% Total net proved developed Net proved undeveloped Peru Our reserves The following table sets forth our oil and natural gas net proved reserves as of December 31, 2014, which is based on the D&M Reserves Report. Total net proved undeveloped Total net proved 6.6 6.6 12.2 12.2 18.8 - - - - - % Oil 100% 100% 6.6 6.6 12.2 100% 12.2 18.8 100% 100% Net proved reserves (1) We calculate one barrel of oil equivalent as six mcf of natural gas. As of December 31, 2014 For further information relating to the reconciliation of our net proved Natural Total net proved reserves for the years ended December 31, 2014, 2013 and 2012, please see Table 5 included in Note 39 (unaudited) to our audited consolidated Oil (mmbbl) gas (bcf) reserves (mmboe)(1) Net proved developed Chile Colombia Argentina Brazil Total net proved developed Net proved undeveloped Chile Colombia Argentina Brazil Total net proved undeveloped Total net proved (Chile, 1.5 7.6 - 0.1 9.1 5.0 17.1 - 0.1 9.4 - - 20.9 30.2 24.6 - - 19.6 financial statements. % Oil 48% Internal controls over reserves estimation process We maintain an internal staff of petroleum engineers and geosciences 100% professionals who work closely with our independent reserves engineers to - ensure the integrity, accuracy and timeliness of data furnished to our 2% independent reserves engineers in their estimation process and who have 3.0 7.6 - 3.5 14.2 64% knowledge of the specific properties under evaluation. Our Director of Development, Carlos Alberto Murut, is primarily responsible for overseeing 9.1 17.1 - 3.3 55% the preparation of our reserves estimates and for the internal control over 100% our reserves estimation. He has more than 30 years of industry experience - 2% as an E&P geologist, with broad experience in reserves assessment, field development, exploration portfolio generation and management and acquisition and divestiture opportunities evaluation. See “-Item 6. Directors, 22.2 44.2 29.6 75% Senior Management and Employees-A. Directors and senior management.” Colombia, Argentina, Brazil) 31.3 74.5 43.7 72% In order to ensure the quality and consistency of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that (1) We calculate one barrel of oil equivalent as six mcf of natural gas. satisfies the following key control objectives: The following table sets forth the oil and natural gas net proved reserves • estimates are prepared using generally accepted practices and as of December 31, 2014, for the Morona Block in Peru which is based on the methodologies; D&M Peru Reserves Report. We expect to close the pending Morona Block • estimates are prepared objectively and free of bias; Acquisition in 2015. 90 GeoPark 20F • estimates and changes therein are prepared on a timely basis; • estimates and changes therein are properly supported and approved; and • estimates and related disclosures are prepared in accordance with regulatory requirements. Throughout each fiscal year, our technical team meets with Independent D&M did not independently verify the accuracy and completeness of Qualified Reserves Engineers, who are provided with full access to complete information and data furnished by us with respect to ownership interests, oil and accurate information pertaining to the properties to be evaluated and gas production, well test data, historical costs of operation and and all applicable personnel. This independent assessment of the internally- development, product prices, or any agreements relating to current and generated reserves estimates is beneficial in ensuring that interpretations future operations of the fields and sales of production. However, if in and judgments are reasonable and that the estimates are free of preparer and the course of the examination something came to the attention of D&M that management bias. brought into question the validity or sufficiency of any such information or data, D&M did not rely on such information or data until it had satisfactorily Recognizing that reserves estimates are based on interpretations and resolved its questions relating thereto or had independently verified judgments, differences between the proved reserves estimates prepared by such information or data. D&M independently prepared reserves estimates us and those prepared by an Independent Qualified Reserves Engineer of to conform to the guidelines of the SEC, including the criteria of “reasonable 10% or less, in aggregate, are considered to be within the range of reasonable certainty,” as it pertains to expectations about the recoverability of reserves differences. Differences greater than 10% must be resolved in the technical in future years, under existing economic and operating conditions, consistent meetings. Once differences are resolved, the independent Qualified Reserves with the definition in Rule 4-10(a)(2) of Regulation S-X. D&M issued the Engineer sends a preliminary copy of the reserves report to be reviewed by D&M Reserves Report based upon its evaluation. D&M’s primary economic the Technical Committee and Directors of each Buisness Unit. A final copy of assumptions in estimates included oil and gas sales prices determined the Reserves Report is sent by the Independent Qualified Reserve Engineer to according to SEC guidelines, future expenditures and other economic be Approved and Signed by the Technical Committee and our CEO and CFO. assumptions (including interests, royalties and taxes) as provided by us. The See “Item 6. Directors, Senior Management and Employees-C. Board Practices- Committees of our Board of Directors.” Independent reserves engineers Reserves estimates as of December 31, 2014 for Brazil, Chile, Colombia and Peru included in this annual report are based on the D&M Reserves Report, assumptions, data, methods and procedures used, including the percentage of our total reserves reviewed in connection with the preparation of the D&M Reserves Report were appropriate for the purpose served by such report, and D&M used all methods and procedures as it considered necessary under the circumstances to prepare such reports. completed on March 9, 2015 and effective as of December 31, 2014. However, uncertainties are inherent in estimating quantities of reserves, The D&M Reserves Report, a copy of which has been filed as an exhibit to including many factors beyond our and our independent reserves engineers’ this annual report, was prepared in accordance with SEC rules, regulations, control. Reserves engineering is a subjective process of estimating subsurface definitions and guidelines at our request in order to estimate reserves and accumulations of oil and natural gas that cannot be measured in an exact for the areas and period indicated therein. manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different D&M, a Delaware corporation with offices in Dallas, Houston, Calgary, engineers often vary, sometimes significantly. In addition, physical factors Moscow and Algiers, has been providing consulting services to the oil and gas industry for more than 75 years. The firm has more than 150 professionals, such as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or including engineers, geologists, geophysicists, petrophysicists and development and production expenses, and regulatory factors, such as economists that are engaged in the appraisal of oil and gas properties, the royalties, development and environmental permitting and concession evaluation of hydrocarbon and other mineral prospects, basin evaluations, terms, may require revision of such estimates. Our operations may also be comprehensive field studies and equity studies related to the domestic affected by unanticipated changes in regulations concerning the oil and gas and international energy industry. D&M restricts its activities exclusively to industry in the countries in which we operate, which may impact our ability consultation and does not accept contingency fees, nor does it own to recover the estimated reserves. Accordingly, oil and natural gas quantities operating interests in any oil, gas or mineral properties, or securities or notes ultimately recovered will vary from reserves estimates. of its clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm. Technology used in reserves estimation According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated The D&M Reserves Report covered 100% of our total reserves. In connection with “reasonable certainty” to be economically producible-from a given with the preparation of the D&M Reserves Report, D&M prepared its own date forward, from known reservoirs, and under existing economic estimates of our proved reserves. In the process of the reserves evaluation, conditions, operating methods and government regulations-prior to the GeoPark 20F 91 time at which contracts providing the right to operate expire, unless Estimates must be prepared using all available information (open and evidence indicates that renewal is reasonably certain, regardless of whether cased hole logs, core analyses, geologic maps, seismic interpretation, deterministic or probabilistic methods are used for the estimation. production/injection data and pressure test analysis). Supporting data, such as working interest, royalties and operating costs, must be The project to extract the hydrocarbons must have commenced or the maintained and updated when such information changes materially. operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered Proved undeveloped reserves As of December 31, 2014, excluding reserves from the pending acquisition will equal or exceed the estimate. Reasonable certainty can be established of the Morona Block, we had 29.6 mmboe in proved undeveloped reserves using techniques that have been proved effective by actual production an increase of 16.6 mmboe, or 127%, over our December 31, 2013 proved from projects in the same reservoir or an analogous reservoir or by other undeveloped reserves of 13.0 mmboe. The increase in proved undeveloped evidence using reliable technology that establishes reasonable certainty. oil reserves is mainly due to net additions in Colombia mainly related to Reliable technology is a grouping of one or more technologies (including the Tigana Field amounting to 11.0 mmboe, in Chile amounting to computational methods) that have been field tested and have been 2.3 mmboe related to the Fell Block, and in Brazil as a result of the acquisition demonstrated to provide reasonably certain results with consistency and of Rio das Contas that we closed in March 31, 2014, amounting to 3.3 mmboe. repeatability in the formation being evaluated or in an analogous formation. Of our 29.6 mmboe of net proved undeveloped reserves, 9.1 mmboe, There are various generally accepted methodologies for estimating reserves 17.1 mmboe, 3.3 mmboe or 31%, 58%, 11%, were located in Chile, Colombia, including volumetrics, decline analysis, material balance, simulation models Brazil, respectively. During 2014, we incurred approximately US$139.3 and analogies. Estimates may be prepared using either deterministic (single million in capital expenditures to convert such proved undeveloped reserves estimate) or probabilistic (range of possible outcomes and probability of to proved developed reserves, of which approximately US$82.7 million, occurrence) methods. The particular method chosen should be based on US$55.3 million and US$1.1 million were made in Chile, Colombia and Brazil the evaluator’s professional judgment as being the most appropriate, given respectively. No net proved undeveloped reserves were located in Argentina the geological nature of the property, the extent of its operating history as of December 31, 2014. As of December 31, 2014 we had 29.6 mmboe in and the quality of available information. It may be appropriate to employ proved undeveloped reserves. several methods in reaching an estimate for the property. As of December 31, 2014, the Morona Block in Peru had 12.2 mmboe in proved undeveloped reserves. We expect to close the pending Morona Block Acquisition in 2015. 92 GeoPark 20F Production, revenues and price history The following table sets forth certain information on our production of oil and natural gas in Chile, Colombia, Brazil and Argentina for each of the years ended December 31, 2014, 2013 and 2012. 2014 (4) Total 2013 Total Average daily production(1) As of December 31, 2012 Total Chile Colombia Brazil Argentina GeoPark Chile Colombia (2) Brazil Argentina GeoPark Chile Colombia Brazil Argentina GeoPark Oil production Average crude oil production (bopd) 3,690 10,748 42 61 14,541 4,581 6,482 89.4 73.0 102.4 75.4 77.5 84.3 80.3 Average sales price of crude oil (US$/bbl)(4) Natural gas Average natural gas production (mcfpd) 14,484 354 15,753 86 30,677 14,283 52 Average sales price of natural gas (US$/mcf)(4) Oil and gas production cost Average 6.2 operating cost - 6.5 1.1 6.4 5.0 4.18 (US$/boe) 16.7 18.4 5.8 11.3 16.2 12.2 26.5 Average royalties and Other (US$/boe) Average production cost (US$/boe)(3) Average depreciation (US$/boe) Average production cost 3.3 3.3 3.1 8.8 3.3 2.9 4.1 20.0 21.7 8.9 20.1 19.5 15.1 30.6 17.5 13.7 12.7 3.4 14.7 11.5 16.6 (US$/boe) 37.6 35.4 21.6 23.5 34.5 26.6 47.2 - - - - - - - - - 50 11,113 4,013 3,431 70.3 82.0 85.42 97.15 84 14,419 22,663 56 1.1 5.0 4.04 4.18 4.0 19.0 10.7 34.0 8.3 3.5 2.5 4.0 12.3 22.5 13.2 38.1 2.5 13.9 9.9 20.4 14.8 36.4 23.1 58.4 - - - - - - - - - 48 7,491 67.8 90.5 84 22,804 1.1 4.0 (6.7) 16.8 7.6 2.9 0.9 19.7 142.1 13.4 143.0 33.1 (1) We present production figures net of interests due to others, but before (3) Calculated pursuant to FASB ASC 932. deduction of royalties, as we believe that net production before royalties is (4) Averaged realized sales price for oil does not include our Argentine blocks more appropriate in light of our foreign operations and the attendant because our Argentine operations were not material during such periods. royalty regimes. Averaged realized sales price for gas does not include our Argentine and (2) We acquired Winchester and Luna in February 2012 and Cuerva in March Colombian blocks because our gas operations in those countries were not 12. Production figures do not include, for 2012, production for Winchester, material during such period. Luna and Cuerva prior to their acquisition by us. GeoPark 20F 93 Drilling activities The following table sets forth the exploratory wells we drilled as operators in Chile, Colombia, Brazil and Argentina during the years ended December 31, 2014, 2013 and 2012. Exploratory wells(1) As of December 31, Chile Colombia Argentina 2014 Brazil Chile Colombia(4) Argentina 2013 Brazil Chile Colombia Argentina 2012 Brazil Productive(2) Gross Net Dry(3) Gross Net Total Gross Net 11.0 7.1 5.0 3.0 16.0 10.1 4.0 1.8 - - - - - - - - - - - - - - - - 7.0 4.8 3.0 1.5 10.0 6.3 9.0 6.0 1.0 1.0 10.0 7.0 - - - - - - - - - - - - 8.0 8.0 6.0 4.5 14.0 12.5 4.0 2.4 3.0 2.5 7.0 4.9 - - - - - - - - - - - - (1) Includes appraisal wells. (4) We acquired Winchester and Luna in February 2012 and Cuerva in (2) A productive well is an exploratory, development, or extension well that March 12. Figures do not include, for 2012, exploration activities for is not a dry well. Winchester, Luna and Cuerva prior to their acquisition by us. (3) A dry well is an exploratory, development, or extension well that proves The following table sets forth the development wells we drilled in Chile, to be incapable of producing either oil or gas in sufficient quantities to justify Colombia, Brazil and Argentina during the years ended December 31, 2014, completion as an oil or gas well. 2013 and 2012. Development wells As of December 31, Chile Colombia Argentina 2014 Brazil Chile Colombia Argentina 2013 Brazil Chile Colombia(1) Argentina 2012 Brazil Productive(2) Gross Net Dry(3) Gross Net Total Gross Net 16.0 15.0 - - 16.0 15.0 5.0 2.3 2.0 0.9 7.0 3.2 - - - - - - - - - - - - 6.0 6.0 1.0 1.0 7.0 7.0 5.0 2.8 - - 5.0 2.8 - - - - - - - - - - - - 4.0 4.0 2.0 2.0 6.0 6.0 6.0 5.5 2.0 2.0 8.0 7.5 - - - - - - - - - - - - (1) We acquired Winchester and Luna in February 2012 and Cuerva in March is not a dry well. 2012. Figures do not include, for 2012, exploration activities for Winchester, (3) A dry well is an exploratory, development, or extension well that proves Luna and Cuerva prior to their acquisition by us. to be incapable of producing either oil or gas in sufficient quantities to justify (2) A productive well is an exploratory, development, or extension well that completion as an oil or gas well. 94 GeoPark 20F For the year ended December 31, 2014, there were no exploratory wells or development wells drilled in our pending Morona Block acquisition, which is expected to close in 2015. Developed and undeveloped acreage The following table sets forth certain information regarding our total gross Productive wells The following table sets forth our total gross and net productive wells as of March 31, 2015. Productive wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells and net developed and undeveloped acreage in Chile, Colombia, Argentina in which we have an interest, and net wells are the sum of our fractional and Brazil as of December 31, 2014. working interests owned in gross wells. Chile Colombia Acreage(1) Argentina (in thousands of acres) Brazil Total developed acreage Gross Net Total undeveloped acreage Gross Net Total developed and undeveloped acreage Gross Net 8.0 7.6 6.9 6.7 6.8 4.4 5.7 2.8 14.9 14.3 12.5 7.2 4.1 0.4 0.0 0.0 4.1 0.4 - - - - - - Oil wells Gross Net Gas wells Gross Net Chile Colombia(2) Productive wells(1) Brazil Argentina 65.0 61.1 30.0 27.8 84.0 40.8 - - 5.0 5.0 - - - - 6.0 0.6 (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 (1) Defined as acreage assignable to productive wells. Net acreage based on 2012. Figures include wells drilled by Winchester, Luna and Cuerva prior to our working interest. their acquisition by us. For the year ended December 31, 2014, total developed acreage in Peru For the year ended December 31, 2014, there were no productive gas wells in was 1.1 thousand acres (gross) and 0.8 thousand acres (net). Total our pending Morona Block acquisition, which we expect to close in 2015. undeveloped acreage was 2.1 thousand acres (gross) and 1.6 thousand acres (net). Total developed and undeveloped acreage was 3.2 thousand acres (gross) and 2.4 thousand acres (net). GeoPark 20F 95 Present activities The following table shows the number of wells in Chile, Colombia, Brazil and Argentina that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of March 31, 2015. Oil wells Gross Net Gas wells Gross Net Wells in process of being drilled or in active completion(1) Brazil Argentina Colombia Chile - - - - - - - - - - - - - - - - Chile 3.0 2.0 1.0 0.5 Wells suspended or waiting on completion(2) Brazil Argentina Colombia - - - - - - - - - - - - (1) We consider wells to be in active completion when we have begun promote the development of gas reserves. Through this new agreement, procedures used in finishing and equipping them for production. the Company completed the drilling of five new gas wells during 2012. (2) We consider wells to be waiting on completion when we have completed Methanex contributed to the cost of drilling the wells in order to improve the drilling in such wells but have not yet begun to perform testing procedures. project economies of scale. The Company fulfilled all the commitments under Marketing and delivery commitments Chile Our customer base in Chile is limited in number and primarily consists of this Agreement. The Agreement also included monthly commitments for delivering certain volumes of gas and in case of failure to do so, the Company could satisfy the obligation through future deliveries without a penalty during three month period. As of December 31, 2012, the accrued penalty for ENAP and Methanex. For the year ended December 31, 2014 we sold 100% under delivered volumes amounted to US$1.7 million which was recorded in of our oil production in Chile to ENAP and 99% of our gas production to “Provisions for other liabilities” in our Financial Statements as of that date. Methanex, with sales to ENAP and Methanex accounting for 6% and 28%, respectively, of our revenues in the same period. On April 1, 2014, the Company and Methanex executed a fifth amendment to the Methanex Gas Supply Agreement, valid until April 30, 2015, which Under our oil sales agreement with ENAP, or the ENAP Oil Sales Agreement, extended the fourth amendment terms and conditions to May 18, 2014, ENAP has committed to purchase our oil production in the Fell Block, in the and defined new conditions for the winter 2014 period (May 2014 to amounts that we produce, and with the limitation being storage capacity at the Gregorio Terminal. The sales contract with ENAP is commonly revised September 2014) and the post winter period (October 2014 to April 2015). For the post winter period the Company committed to deliveries of over every year to reflect changes in the global oil market and to adjust to logistics 400,000 SCM/d. The fifth amendment also waived the DOP and TOP costs of ENAP in the Gregorio oil terminal. As of the date of this Annual thresholds for both parties, replacing them by reasonable efforts to deliver Report, we are negotiating a new agreement with an initial term of three to and take, and giving GeoPark’s gas first priority over any third party supplies six months, effective April 2015. to Methanex. Commercial conditions of the amended contract are similar to the previous We gather the gas we produce in several wells through our own flow lines one in effect. We deliver the oil we produce in the Fell Block to ENAP at and inject it into several gas pipelines owned by ENAP. The transportation of the Gregorio Terminal, where ENAP assumes responsibility for the oil. ENAP the gas we sell to Methanex through these pipelines is pursuant to a private owns two refineries in Chile in the north central part of the country and must contract between Methanex and ENAP. We do not own any principal natural ship any oil from the Gregorio Terminal to these refineries unless it is gas pipelines for the transportation of natural gas. consumed locally. The Company signed the Methanex Gas Supply Agreement in Chile in 2009, temporarily delay production and sale of our oil and gas in Chile. For a which expires in 2017. In March 2012, the Company and Methanex signed a discussion of the risks associated with the loss of key customers, See “-Item 3. third addendum and amendment to the Methanex Gas Supply Agreement to Key Information-D. Risk factors-Risks relating to our business-We sell almost If we were to lose any one of our key customers in Chile, the loss could 96 GeoPark 20F all of our natural gas in Chile to a single customer, who has in the past Petrobras, which provides for the delivery and transportation of the gas temporarily idled its principal facility” and “-We derive a significant portion produced in the Manatí Field to the EVF gas treatment plant in the State of our revenues from sales to a few key customers.” of Bahia. The contract is in effect until delivery of the maximum committed volume or June 2030, whichever occurs first. The contract allows for Colombia Our production in Colombia consists almost exclusively of oil. Our oil sales sales above the maximum committed volume if mutually agreed by both seller and buyer. As of the date of this Annual Report, we are negotiating agreements are generally for a fixed term, with a maximum length of one an amendment to the contract in order to provide for the purchase and sale year. They do not commit the parties to a minimum volume, and are subject of additional volumes, pending the closing of the gas compression facility. to the ability of either party to receive or deliver production. The contracts The price for the gas is fixed in reais and is adjusted annually in accordance generally provide that they can be renewed by mutual written agreement, with the Brazilian inflation index. and all allow for early termination by either party with advanced notice and without penalty. The Manatí Field is developed via a PMNT-1 production platform, which is connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant The delivery points for our production range from the well-head to the port through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd of export (Coveñas), depending on the client. If sales are made via pipeline, (9.5 mm3 per day). The existing pipeline connects the field’s platform to the delivery point is usually the pipeline injection point, whereas for direct the EVF gas treatment plant, which is owned by the field’s current concession export sales, the most frequent delivery point is the well-head. In Colombia, holders. The BCAM-40 Concession, which includes the Manatí Field, also the restrictions to access pipeline networks, especially for mid to heavy benefits from the advantages of Petrobras’ size. As the largest onshore and crudes, have forced the market to access different ways of transport and offshore operator in Brazil, Petrobras has the ability to mobilize the resources commercialization, reducing our dependency on pipeline infrastructure necessary to support its activities in the concession. significantly. For the year ended December 31, 2014, we sold approximately 53% of our production directly at the well-head and approximately 47% to The condensate produced in the Manatí Field is subject to a condensate the major oil companies that own capacity in the pipelines. In 2014, access purchase agreement with Petrobras, pursuant to which Petrobras has to the pipeline network has improved upon the commencement of the committed to purchase all of our condensate production in the Manatí Field, Bicentenario pipeline, which added transportation capacity of 100,000 bopd but only in the amounts that we produce, without any minimum or and also open up additional supply opportunities involving reduced maximum deliverable commitment from us. The agreement is valid through trucking costs. Since as of December 31, 2014 we do not own capacity in, or December 31, 2015, but can be renewed upon an amendment signed by have access to, the oil transportation pipelines in Colombia or have any Petrobras and the seller. other assets for the transportation of our commodities, we use third parties to transport our production by pipeline or truck. If the agreements with Petrobras were terminated, this could temporarily delay production and sale of our natural gas and condensate oil in Brazil, and The price of the oil that we sell under these agreements is based on a market reference price (Brent, WTI or Vasconia), adjusted for certain marketing could have a detrimental effect on our ability to find substitute customers to purchase our production volumes. and quality discounts based on, among other things, API, viscosity, sulphur and water content, as well as for certain transportation costs (including pipeline costs and trucking costs). Peru In Peru, oil production is generally traded on a free market basis and contracts commercial conditions generally follow international markers, normally WTI For the year ended December 31, 2014, we made 40.1% of our oil sales to and Brent. As per the Petroperú SPA, Petroperú holds the first option, but Gunvor, 31.8% to Emerald and 11.0% to Perenco, with Gunvor accounting not the obligation, to purchase oil produced by us in the Morona Block. If we for 23.0%, Emerald 18.3% and Perenco 6.3% of our consolidated revenues for are not able to sell our production share at the Block or in Morona Station, the same period. If we were to lose any one of our key customers, the loss we will have to use the North Peruvian Pipeline. This transportation system could temporarily delay production and sale of our oil in the corresponding is owned and operated by Petroperú, and regulated and supervised by block. However, we believe we could identify a substitute customer to OSINERGMIN, the regulatory body in the hydrocarbons sector. Transportation purchase the impacted production volumes. rates should be negotiated with Petroperú. However, if an agreement cannot Brazil Our production in Brazil consists of natural gas and condensate oil. Natural gas production is sold through a long-term, extendable agreement with be reached between Petroperú and us, transportation rates will be determined by OSINERGMIN. GeoPark 20F 97 Argentina In Argentina, we sell substantially all of our oil production to Oil Combustibles, but because the volume we produce in Argentina is small and the rights contained in a CEOP cannot be modified without consent of the parties. the sale price is fixed at the moment when all other producers have Our CEOPs are subject to early termination in certain circumstances, which delivered their product to the Punta Loyola terminal, from which we sell our vary depending upon the phase of the CEOP. During the exploration phase, crude, we do not sell our oil to Oil Combustibles at a predetermined formula Chile may terminate a CEOP in circumstances including a failure by us to or price, but rather on the basis of on-call contracts based on demand. comply with minimum work commitments at the termination of any We have the ability to store and process the oil we produce in Argentina with the next exploration period 30 days prior to its termination, a failure ourselves, and do not have material contracts with third parties for such to provide the Chilean Ministry of Energy the performance bonds required services. We enter into ad hoc contracts with local companies for the under the CEOP, a voluntary relinquishment by us of all areas under the transportation of crude from fields in the Del Mosquito Block to the Punta CEOP or a failure by us to meet the requirements to enter into the exploration period, or a failure to communicate our intention to proceed Loyola terminal. Significant agreements Chile CEOPs We have entered into six CEOPs with Chile, one for each of the blocks in exploitation phase upon the termination of the exploration phase. In the exploitation phase, Chile may terminate a CEOP if we stop performing any of the substantial obligations assumed under the CEOP without cause and do not cure such nonperformance pursuant to the terms of the concession, following notice of breach from the Chilean Ministry of Energy. Additionally, Chile may terminate the CEOP due to force majeure circumstances (as defined which we operate, which grant us the right to explore and exploit in the relevant CEOP). If Chile terminates a CEOP in the exploitation phase, hydrocarbons in these blocks, determine our working interests in the blocks we must transfer to Chile, free of charge, any productive wells and related and appoint the operator of the blocks. These CEOPs are divided into two facilities, provided that such transfer does not interfere with our phases: (1) an exploration phase, which is divided into two or more abandonment obligations and excluding certain pipelines and other assets. exploration periods, and which begins on the effectiveness date of the Other than as provided in the relevant CEOP, Chile cannot unilaterally relevant CEOP, and (2) an exploitation phase, which is determined on a per- terminate a CEOP without due compensation. See “-Item 3. Key Information- field basis, commencing on the date we declare a field to be commercially D. Risk factors-Risks relating to our business-Our contracts in obtaining viable and ending with the term of the relevant CEOP. In order to transition rights to explore and develop oil and natural gas reserves are subject to from the exploration phase to an exploitation phase, we must declare a contractual expiration dates and operating conditions, and our CEOPs, E&P discovery of hydrocarbons to the Ministry of Energy. This is a unilateral Contracts and concession agreements are subject to early termination in declaration, which grants us the right to test a field for a limited period of certain circumstances.” time for commercial viability. If the field proves commercially viable, we must make a further unilateral declaration to the Ministry of Energy. In the Fell Block CEOP. On November 5, 2002, we acquired a percentage of rights exploration phase, we are obligated to fulfill a minimum work commitment, which generally includes the drilling of wells, the performance of 2D or and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and on May 10, 2006, we became the sole owners, with 100% of the 3D seismic surveys, minimum capital commitments and guaranties or letters rights and interest in the Fell Block CEOP. Chile had originally entered into a of credit, as set forth in the relevant CEOP. We also have relinquishment CEOP for the Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, obligations at the end of each period in the exploration phase in respect on April 29, 1997, which had an effective date of August 25, 1997. The Fell of those areas in which we have not made a declaration of discovery. Block CEOP grants us the exclusive right to explore and exploit hydrocarbons We can also voluntarily relinquish areas in which we have not declared in the Fell Block and has a term of 35 years, beginning on the effective date. discoveries of hydrocarbons at any time, at no cost to us. In the exploitation The Fell Block CEOP provided for a 14-year exploration period, composed phase, we generally do not face formal work commitments, other than of numerous phases that ended in 2011, and an up-to-35-year exploitation the development plans we file with the Chilean Ministry of Energy for each phase for each field. field declared to be commercially viable. Our CEOPs provide us with the right to receive a monthly remuneration from Chile payable in petroleum and gas, based on the following per-field from Chile, payable in petroleum and gas, based either on the amount of formula: 95% of the oil produced in the field, for production of up to petroleum and gas production per field or according to Recovery Factor, 5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for which considers the ratio of hydrocarbon sales to total cost of production production of up to 882.9 mmcfpd. In the event that we exceed these levels (capital expenditures plus operating expenses). Pursuant to Chilean law, of production, our monthly retribution from Chile will decrease based on a The Fell Block CEOP provides us with a right to receive a monthly retribution 98 GeoPark 20F sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the Pursuant to our E&P Contracts, we are required, as are all oil and gas oil and 60% of the gas that we produce per field. companies undertaking exploratory and production activities in Colombia, to pay a royalty to the Colombian government based on our production TDF Blocks CEOPs. After an international bidding process led by ENAP and of hydrocarbons, as of the time a field begins to produce. Under Law 756 the Chilean Ministry of Energy, in March and April, 2012, GeoPark together of 2002, as modified by Law 1530 of 2012, the royalties we must pay in with ENAP, signed 3 new CEOPs for the Blocks Isla Norte, Campanario connection with our production of light and medium oil are calculated on a and Flamenco, all of them located in Tierra del Fuego, Magallanes region. field-by-field basis, using the following sliding scale: GeoPark’s working interest is 60% in Isla Norte and 50% in Campanario and Flamenco Blocks. The CEOPs have a term of 25 years, with an initial Exploration Phase which last for 7 years, including a first period of 3 years in which GeoPark is committed to develop several exploration activities including 1,500 square kilometers of 3D seismic registration, and the drilling of 21 exploratory wells. The decision to continue to the second 2-years’ Production (mbop) Up to 5,000 5,000 to 125,000 125,000 to 400,000 exploration period has to be taken at the end of 2015. GeoPark and ENAP 400,000 to 600,000 have agreed to ask the Ministry for an extension period of 18 months for Greater than 600,000 the first 3-year period for the Campanario and Isla Norte Blocks, in order to Production royalty rate 8% 8-20% 20% 20-25% 25% re-evaluate the preliminary results of the drilling campaign and to add In the case of natural gas, the royalties are 80% of the rates presented above new exploration objectives to the original geological plan. for the exploitation of onshore and offshore fields at depths less than or equal to 304.8 meters, and 60% for the exploitation of offshore fields at depths The hydrocarbon discoveries opened up an Exploitation Phase that lasts exceeding 304.8 meters. For new discoveries of heavy oil, classified as oil with up to 25 years. GeoPark discovered hydrocarbon fields in the 3 Blocks, an API equal to or less than 15°, the royalties are 75% of the rates presented starting 2013 in the Flamenco Block, and in 2014 in both Campanario and above. Additionally, in the event that an exploitation area has produced Isla Norte Blocks. The CEOPs provide GeoPark with a right to receive a amounts in excess of an aggregate amount established in the E&P Contract remuneration payable by means of a fraction of the production sold, which governing such area, the ANH is entitled to receive a “windfall profit,” to be in the TDF Blocks is based on a formula depending on the recovery of the paid periodically, calculated pursuant to such E&P Contract. total accumulated expenses incurred (capital expenditure plus operational expenditure plus administrative and general expenses). While the recovery In each of the exploration and exploitation periods, we are also obligated to factor is less than 1.0, the remuneration is 95% of the hydrocarbons pay the ANH a subsoil use fee. During the exploration period, this fee is produced, either oil or gas. If the recovery factor surpasses 1,0, a formula scaled depending on the contracted acreage. During the exploitation period, applies reducing gradually the remuneration fraction to a minimum of 75% the fee is assessed on the amount of hydrocarbons produced, multiplied when the recovery factor is 2,5 times the total accumulated expenses. by a specified dollar amount per barrel of oil produced or thousand cubic feet Colombia E&P Contracts We have entered into E&P Contracts granting us the right to explore and of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P Contract. operate, as well as working interests in, six blocks in Colombia. Additionally, Our E&P Contracts are generally subject to early termination for a breach by we have applied to the ANH to recognize our economic interest in a seventh the parties, a default declaration, application of any of the contract’s unilateral Colombian block as a working interest. These E&P Contracts are generally termination clauses or termination clauses mandated by Colombian law. divided into two periods: (1) the exploration period, which may be subdivided Anticipated termination declared by the ANH results in the immediate into various exploration phases and (2) the exploitation period, determined enforcement of monetary guaranties against us and may result in an action on a per-area basis and beginning on the date we declare an area to be for damages by the ANH. Pursuant to Colombian law, if certain conditions are commercially viable. Commercial viability is determined upon the completion met, the anticipated termination declared by the ANH may also result in a of a specified evaluation program or as otherwise agreed by the parties restriction on the ability to engage contracts with the Colombian government to the relevant E&P Contract. The exploitation period for an area may be during a certain period of time. See “-Item 3. Key Information-D. Risk factors- extended until such time as such area is no longer commercially viable and Risks relating to our business-Our contracts in obtaining rights to explore and certain other conditions are met. develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our CEOPs, E&P Contracts and concession agreements are subject to early termination in certain circumstances.” GeoPark 20F 99 La Cuerva Block E&P Contract. Pursuant to an E&P Contract between us and the ANH that became effective as of April 16, 2008, or the La Cuerva Block E&P respectively. We are currently awaiting for the environmental license required for the declaration of commerciality of the Max and Tua fields to be Contract, we were granted the right to explore and operate, and a 100% expedited. In the meantime the ANH has granted an extension of time for working interest in, the La Cuerva Block. such declaration until the ANLA issues the environmental license. We are currently in the production phase of the La Cuerva Block E&P Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are Contract. Production began in the west, southwest and southern, east and required to pay to the ANH a royalty based on hydrocarbons produced in northeast areas of the Block on December 9, 2011, February 10, 2012, April 23, the Llanos 34 Block. In the Max Field, we pay the ANH a royalty of at least 2012, October 18, 2013 and October 21, 2013 respectively. The La Cuerva 6.0%, and in the Túa, Tarotaro and Tigana Fields, we pay a royalty of at least Block E&P Contract provides for a 24-year exploitation period for each area 8.0%. Additionally, we are required to pay a subsoil use fee to the ANH, in the La Cuerva Block, beginning from the date such area is declared which, during the exploration period, is scaled depending on the contracted commercially viable. acreage, and which, during the exploitation period, is equivalent to the amount of oil we produce multiplied by US$0.1162 per bbl or the amount of Pursuant to the La Cuerva Block E&P Contract and applicable law, we are natural gas we produce multiplied by US$0.01162 per mcf. The ANH also required to pay to the ANH a royalty of at least 8.0% based on hydrocarbons has the right to receive an additional fee when prices for oil or gas, as the produced, in accordance with the table presented above. Additionally, we are case may be, exceed the prices set forth in the Llanos 34 Block E&P Contract. required to pay a subsoil use fee to the ANH, which, during the exploration The ANH also has an additional economic right equivalent to 1% of period, is scaled depending upon the contracted acreage, and which, during production, net of royalties. the exploitation period, is equivalent to the amount of oil we produce multiplied by US$0.1119 per bbl or the amount of natural gas we produce In accordance with the Llanos 34 Block operation contract, when the multiplied by US$0.0119 per mcf. The ANH also has the right to receive accumulated production of each field, including the royalties’ volume, an additional fee when prices for oil or gas, as the case may be, exceed the exceeds 5 million barrels and the WTI exceeds the base price settled in Table prices set forth in the La Cuerva Block E&P Contract. A, the Company should deliver to ANH a share of the production net of Llanos 34 Block E&P Contract. Pursuant to an E&P Contract between Unión Temporal Llanos 34 (a consortium between Ramshorn and GeoPark Colombia SAS) and the ANH that became effective as of March 13, 2009, or the Llanos royalties in accordance with the following formula: Q = ((P - Po)/P) x S; where Q = Economic right to be delivered to ANH, P = WTI, Po = Base price (see Table A) and S = Share (see Table B). 34 Block E&P Contract, Unión Temporal Llanos 34 was granted the right to Table A explore and operate the Llanos 34 Block, and we and Ramshorn were granted a 40% and a 60% working interest, respectively, in the Llanos 34 Block. We °API >29° were also granted the right to operate the Llanos 34 Block. On December 16, >22°<29° 2009, we entered into a joint operating agreement with Ramshorn and P1 Energy in respect of our operations in the Block. On August 31, 2012, the ANH >15°<22° >10°<15° approved the assignment by Ramshorn to us of an additional 5% working interest, giving Ramshorn a 55% working interest and us a 45% working interest in the Llanos 34 Block. Table B Po (US$/barrel) WTI (P) 30.22 31.39 32.56 46.50 Po < P < 2Po 2Po < P < 3Po 3Po < P < 4Po 4Po < P < 5Po 5Po < P S 30% 35% 40% 45% 50% Winchester and Luna Stock Purchase Agreement Pursuant to the stock purchase agreement entered into on February 10, 2012, We are currently in the exploration period of the Llanos 34 Block E&P or the Winchester Stock Purchase Agreement, we agreed to pay the Contract. The contract provides for a six-year exploration period, consisting of Sellers a total consideration of US$30.0 million, adjusted for working capital. two three-year phases, which can be extended for up to six additional months Additionally, under the terms of the Winchester Stock Purchase Agreement, to allow for the completion of exploration activities. The Llanos 34 Block E&P we are obligated to make certain payments to the Sellers based on the Contract provides for a 24-year exploitation period for each commercial area, production and sale of hydrocarbons discovered by exploration wells drilled beginning on the date on which such area is declared commercially viable. after October 25, 2011. The agreement provides that we make a quarterly The exploitation period may be extended for periods of up to 10 years at a payment to the Sellers in an amount equal to 14% of adjusted revenue time, until such time as the area is no longer commercially viable and certain (as defined under the agreement) from any new discoveries of oil, up to the conditions are met. We have presented evaluation programs to the ANH maximum earn-out amount of US$35.0 million (net of Colombian taxes). Once for the Max, Túa, Tarotaro and Tigana Fields, which expire on September 15, the maximum earn-out amount is reached, we will pay the Sellers quarterly 2014, December 2, 2014, and November 15, 2015, and March 25, 2016, overriding royalties in an amount equal to 4% of our net revenues from any 100 GeoPark 20F new discoveries of oil. For the year ended December 31, 2014, we paid Petroleum Law, which provides for the granting of concessions to operate US$21.0 million and accrued US$24.6 million with regards to this agreement. petroleum and gas fields in Brazil, subject to oversight by the ANP. A concession agreement is divided into two phases: (1) exploration and (2) Cuerva purchase and sale agreement Pursuant to the purchase and sale agreement dated March 26, 2012 between development and production. The exploration phase, which is further divided into two subsequent exploratory periods, the first of which begins on the Hupecol Cuerva Holdings LLC, as the Seller, and us, we paid to the Seller a date of execution of the concession agreement, can last from three to eight total consideration of US$75 million, adjusted for working capital. years (subject to earlier termination upon the total return of the concession Brazil Rio das Contas Quota Purchase Agreement Pursuant to the Rio das Contas Quota Purchase Agreement we entered into area or the declaration of commercial viability with respect to a given area), while the development and production phase, which begins for each field on the date a declaration of commercial viability is submitted to the ANP, can last up to 27 years. Upon each declaration of commercial viability, a on May 14, 2013, we agreed to acquire from Panoro all of the quotas issued concessionaire must submit to the ANP a development plan for the field by Rio das Contas for a purchase price of US$140 million (subject to working within 180 days. The concessions may be renewed for an additional period capital adjustments at closing and further earn-out payments, if any) upon equal to their original term if renewal is requested with at least 12 months’ satisfaction of certain conditions. With respect to the earn-out payments, the notice, and provided that a default under the concession agreement has Rio das Contas Quota Purchase Agreement provides that during the calendar not occurred and is then continuing. Even if obligations have been fulfilled periods beginning on January 1, 2013 and ending as late as December 31, under the concession agreement and the renewal request was appropriately 2017, we will make annual earn-out payments to Panoro in an amount equal filed, renewal of the concession is subject to the discretion of the ANP. 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 The main terms and conditions of a concession agreement are set forth Concession of any amounts in excess of US$25.0 million, up to a maximum in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of the cumulative earn-out amount of US$20.0 million in a five-year period. Once concession area; (2) validity and terms for exploration and production the maximum earn-out amount is reached or the five-year period has elapsed, activities; (3) conditions for the return of concession areas; (4) guarantees no further earn-out amounts will be payable. For the year ended December to be provided by the concessionaire to ensure compliance with the 31, 2014, there were no earn-out payments with regards to this agreement. concession agreement, including required investments during each phase; (5) penalties in the event of noncompliance with the terms of the concession We financed our Rio das Contas acquisition in part through our Brazilian agreement; (6) procedures related to the assignment of the agreement; and subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas (7) rules for the return and vacancy of areas, including removal of equipment Credit Facility”) with Itaú BBA International plc, which is secured by the and facilities and the return of assets. Assignments of participation interests benefits GeoPark receives under the Purchase and Sale Agreement for Natural in a concession are subject to the approval of the ANP, and the replacement Gas with Petrobras. The facility matures five years from March 28, 2014, with of a performance guarantee is treated as an assignment. principal annual payments in March and September starting in 2015 and bears interest at a variable interest rate equal to the six-month LIBOR + 3.9%. The main rights of the concessionaires (including us in our concession In March 2015, we reached an agreement to: (i) extend the principal agreements) are: (1) the exclusive right of drilling and production in payments that were due in 2015 (amounting to approximately US$15 million), the concession area; (2) the ownership of the hydrocarbons produced; (3) which will be divided pro-rata during the remaining principal installments, the right to sell the hydrocarbons produced; and (4) the right to export starting in March 2016 and (ii) to increase the variable interest rate equal the hydrocarbons produced. However, a concession agreement set forth that, to the six-month LIBOR + 4.0%. The facility agreement includes customary in the event of a risk of a fuel supply shortage in Brazil, the concessionaire events of default, and subject our Brazilian subsidiary to customary must fulfill the needs of the domestic market. In order to ensure the domestic covenants, including the requirement that it maintain a ratio of net debt to supply, the Brazilian Petroleum Law granted the ANP the power to control EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. The credit the export of oil, natural gas and oil products. facility also limits the borrower’s ability to pay dividends if the ratio of net debt to EBITDA is greater than 2.5x. We have the option to prepay the facility Among the main obligations of the concessionaire are: (1) the assumption in whole or in part, at any time, subject to a pre-payment fee to be of costs and risks related to the exploration and production of hydrocarbons, determined under the contract. including responsibility for environmental damages; (2) compliance with the requirements relating to acquisition of assets and services from domestic Overview of concession agreements The Brazilian oil and gas industry is governed mainly by the Brazilian suppliers; (3) compliance with the requirements relating to execution of the minimum exploration program proposed in the winning bid; (4) activities for GeoPark 20F 101 the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments Under the BCAM-40 Concession Agreement, the ANP is entitled to a for government participation; and (7) responsibility for the costs associated monthly royalty payment equal to 7.5% of the production of oil and natural with the deactivation and abandonment of the facilities in accordance with gas in the concession area. In addition, in case the special participation fee Brazilian law and best practices in the oil industry. of 10% shall be applicable for a field in any quarter of the calendar year, the concessionaire is obliged to make qualified research and development A concessionaire is required to pay to the Brazilian government the following: investments equivalent to one percent of the field’s gross revenue. Area • a license fee; retention payments are also applicable under the concession agreement. We • rent for the occupation or retention of areas; acquired Rio das Contas’s 10% participation interest in the BCAM-40 • a special participation fee; • royalties; and • taxes. Concession on March 31, 2014. Round 11 concession agreements. Additionally, on May 14, 2013, following the 11th oil and gas bidding round pursuant to the Brazilian Petroleum Law, Rental fees for the occupation and maintenance of the concession areas are we were awarded seven new exploratory licenses in Brazil in the REC-T 94 payable annually. For purposes of calculating these fees, the ANP takes into and REC-T 85 Concessions in the Recôncavo Basin in the State of Bahia and consideration factors such as the location and size of the relevant concession, the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions the sedimentary basin and the geological characteristics of the relevant in the Potiguar Basin in the State of Rio Grande do Norte. We have entered concession. into seven concession agreements, which we collectively refer to as the Round 11 Concession Agreements, with the ANP on September 17, 2013, for A special participation fee is an extraordinary charge that concessionaires the right to exploit the oil and natural gas in these seven new license areas. must pay in the event of obtaining high production volumes and/or We have paid to the ANP a license fee in the amount of R$10.2 million profitability from oil fields, according to criteria established by applicable (approximately US$4.4 million), consisting of R$7.2 million for the REC-T 94 regulations, and is payable on a quarterly basis for each field from the date on and REC-T 85 Concessions and R$3.0 million for the POT-T 664, POT-T 665, which extraordinary production occurs. This participation fee, whenever due, POT-T 619, POT-T 620 and POT-T 663 Concessions, and provide to the ANP varies between 0% and 40% of net revenues depending on (1) the volume financial guarantees in the amount of R$20.4 million (approximately of production and (2) whether the concession is onshore or in shallow water US$6.4 million, at the March 31, 2015 exchange rate of R$3.2080 to US$1.00), or deep water. Under the Brazilian Petroleum Law and applicable regulations consisting of R$12.1 million (approximately US$3.8 million, at the March 31, issued by the ANP, the special participation fee is calculated based on 2015 exchange rate of R$3.2080 to US$1.00) for the REC-T 94 and REC-T 85 the quarterly net revenues of each field, which consist of gross revenues Concessions and R$8.3 million (approximately US$2.6 million, at the Mach 31, calculated using reference prices established by the ANP (reflecting 2015 exchange rate of R$3.2080 to US$1.00) for the POT-T 664, POT-T 665, international prices and the exchange rate for the period) less: POT-T 619, POT-T 620 and POT-T 663 Concessions, to secure our obligations • royalties paid; • investment in exploration; • operational costs; and under the Minimum Exploratory Programs, or PEMs, for the first exploratory period of the concessions. • depreciation adjustments and applicable taxes. Under the Round 11 Concession Agreements, the ANP is entitled to a The Brazilian Petroleum Law also requires that the concessionaire of onshore gas in the concession area, in addition to the special participation fee fields pay to the landowners a special participation fee that varies between described above, the payment for the occupation of the concession area of 0.5% to 1.0% of the net operational income originated by the field approximately R$7,600 (approximately US$2,400 at the March 31, 2015 monthly royalty corresponding to 10% of the production of oil and natural production. BCAM-40 Concession Agreement. On August 6, 1998, the ANP and Petrobras executed the concession agreement governing the BCAM-40 Concession, or the BCAM-40 Concession Agreement, following the first round of bidding, referred to as Bid Round Zero, under the regime established by the exchange rate of R$3.2080 to US$1.00) 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. On November 28, 2013, following the 12th oil and gas bidding round Brazilian Petroleum Law. The exploration phase will end in November 2029. pursuant to the Brazilian Petroleum Law, we were awarded two new On September 11, 2009, Petrobras announced the termination of BCAM-40 exploratory licenses in Brazil, the PN-T-597 Concession on the Parnaiba Basin Concession’s exploration phase and the return of the exploratory area of the in the State of Maranhão and the SEAL-T-268 Concession in the Sergipe- concession to the ANP, except for the Manatí Field and the Camarão Norte Field. Alagoas Basin in the State of Alagoas. 102 GeoPark 20F Our offer requires a commitment to the ANP of R$9.3 million (approximately operator of the BCAM-40 concession, with a 35% participation interest. QGEP, US$2.9 million, at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) Brasoil and Rio das Contas have a 45%, 10% and 10% participation interest, composed of R$1.6 million (approximately US$0.5 million, at the March 31, respectively. The BCAM-40 Consortium Agreement has a specified term 2015 exchange rate of R$3.2080 to US$1.00) for the first exploratory period on of 40 years, terminating on January 14, 2040 and, at the time the obligations the Concession SEAL-T-268 and R$7.7 million (approximately US$2.4 million, undertaken in the agreement are fully completed, the parties will have the at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) for the first right to terminate it. The BCAM-40 Concession consortium has also entered exploratory period on the PN-T-597. into a joint operating agreement, which sets out the rights and obligations of the parties in respect of the operations in the concession. Part of our bid for the Round 12 concessions was comprised of work program guarantees, or commitments to invest certain sums in the blocks as part our exploration activities. Our SEAL-T-268 commitment is composed Petrobras Natural Gas Purchase Agreement QGEP, GeoPark Brazil, Brasoil and Petrobras are party to a natural gas of R$0.14 million (approximately US$0.04 million, at the March 31, 2015 purchase agreement providing for the sale of natural gas by QGEP, GeoPark exchange rate of R$3.2080 to US$1.00) bonus payable to the ANP and Brazil and Brasoil to Petrobras, in an amount of 812 bcf over the term of R$1.5 million (approximately US$0.5 million, at the March 31, 2015 exchange agreement. The Petrobras Natural Gas Purchase Agreement is valid until the rate of R$3.2080 to US$1.00) as part of the work program guarantee payable earlier of Petrobras’s receipt of this total contractual quantity or June 30, over the course of the three years. Work program is equivalent to 40 km of 2D 2030. The agreement may not be fully or partially assigned except upon seismic, with no well drilling committed during the first exploratory period. execution of an assignment agreement with the written consent of the other parties, which consent may not be unreasonably withheld provided that Our PN-T-597 commitment is composed of R$0.9 million (approximately certain prerequisites have been met. US$0.3 million, at the March 31, 2015 exchange rate of R$3.2080 to US$1.00) bonus payable to the ANP in the first year of exploration and R$6.7 million The agreement provides for the provision of “daily contractual quantities” to (approximately US$2.1 million, at the March 31, 2015 exchange rate of Petrobras, in the following amounts: from the first year through the end of R$3.2080 to US$1.00) as a work program guarantee. See “-Item 3. Key the fourth year under the contract, 211.9 mmcfpd; from the beginning of information-D. Risk factors-Risks relating to our business-The \PN-T-597 the fifth year through the end of the ninth year, 141.3 mmcfpd; and from the concession is subject to an injunction and may not close.” for more beginning of the tenth year through the end of the contract, 141.3 mmcfpd information. or such smaller quantity as stipulated by the parties, to take into account the Manatí Field’s depletion. Pursuant to the agreement, the base price is Overview of consortium agreements A consortium agreement is a standard document describing consortium denominated in reais and is adjusted annually for inflation pursuant to the general index of market prices (IGPM). Additionally, the gas price applicable members’ respective percentages of participation and appointment of the on a given day is subject to reduction as a result of the gas quantity operator. It generally provides for joint execution of oil and natural gas acquired by Petrobras above the volume of the annual TOP commitment exploration, development and production activities in each of the concession areas. These agreements set forth the allocation of expenses for each (85% of the daily contracted quantity) in effect on such day. of the parties with respect to their respective participation interests in the The Petrobras Natural Gas Purchase Agreement provides that if the Manatí concession. The agreements are supplemented by joint operating Field’s daily production capacity is less than the amount of the applicable agreements, which are private instruments that typically regulate the daily contractual quantity, gas sales shall be made exclusively to Petrobras, aggregation of funds, the sharing of costs, mitigation of operational risks, with any sales to third parties subject to a penalty. If the field’s production is preemptive rights and the operator’s activities. above the applicable daily contractual quantity, the agreement provides that Petrobras must first be offered to purchase the excess amount of gas. An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph 1, of the Brazilian Corporate Law) is the joint liability among consortium Petrobras Natural Gas Condensate Purchase Agreement On January 1, 2014, Rio das Contas and Petrobras entered into an agreement, members as established in the Brazilian Petroleum Law (Article 38, item II). the Petrobras Natural Gas Condensate Purchase Agreement, valid until BCAM-40 Consortium Agreement. On January 14, 2000, the consortium total volume of natural gas condensate to be produced in the Manatí Field. formed by Petrobras, QG Perfurações and Petroserv entered into a The agreement can be renewed and takes into consideration market factors consortium agreement, or the BCAM-40 Consortium Agreement, for the that affect the production and sale of gas. December 31, 2015 for the sale to Petrobras of Rio das Contas’s share of the performance of the BCAM-40 Concession Agreement. Petrobras is the GeoPark 20F 103 Pursuant to the agreement, for each liquid barrel of condensed natural gas and production or meet other limited requirements, as established under sold by Rio das Contas, Petrobras will pay the monthly arithmetic average Presidential Decree 616/2005. of the averages of the daily prices for the “BRENT DTD” barrel, as published by Platt’s Crude Oil Marketwire, subject to a discount of $2.87 per barrel. In general, our Argentina concession agreement for the Del Mosquito Block grant us the exclusive right to produce, explore and develop Any assignment of a party’s interest under the agreement requires the other hydrocarbons in these blocks, as well as the right to receive a transportation party’s prior written consent. Peru Morona Block Acquisition On October 1, 2014, we entered into an agreement with Petroperú to concession to build unused pipelines or other transportation facilities beyond the boundaries of the concessions for 35 years. The term of each of these concessions is 25 years, with an optional extension of up to 10 years. There is no minimum work or investment commitment under any of the concessions other than the general requirement to make needed investments acquire an interest in and operate the Morona Block, located in Northern to develop the entire acreage of the concession, though the Argentine Peru. GeoPark will assume a 75% working interest of the Morona Block, Secretary of Energy takes into account all work and investment undertaken with Petroperú retaining a 25% working interest. when determining whether to grant an extension of the concession term. Work and investment programs for the concessions are required to be The transaction is subject to conditions precedents, which include the presented annually to the incumbent Provincial State enforcement authority, qualification of GeoPark by Perupetro, which has already been fulfilled, certain the Argentine Secretary of Energy and the Strategic Planning and modifications to the License Contract, and the enactment of a Supreme Decree Coordination Committee for the National Hydrocarbon Investment Plan. of the President of Peru. The transaction is expected to close in 2015. Under the terms of our concession agreements, we are entitled to 100% of The agreement includes a work program and development plan, for Situche production, with no governmental participation. We are also required, under Central oil field, in the Morona Block, to be completed in stages. Initial stage Argentine law, to pay royalties to certain Argentine provinces, at a rate of goal will be to start production through a long term test, which also will be 12% on both oil and gas sales. In addition to this 12% royalty, we are also used to define the most effective development plan and to start generating required to pay additional royalties ranging from 2.5% to 8%, pursuant to cash flow. GeoPark has committed to carry Petroperú’s share of the capital private royalty agreements we have entered into. We also pay annual surface expenses required to carry out the long term test in the wells SC2X and SC3X. rental fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) The subsequent work program stages, which will be initiated once production and Resolution 588/98 of the Argentine Secretary of Energy and Decree has been established, are focused on carrying out the full development of 1454/2007, and certain landowner fees. the Situche Central field, including transportation infrastructure. Petroperú will also have the right to increase its working interest in the Block up to 50%, Our Argentine concession agreements have no change of control provisions, subject to GeoPark recovering its investments in the Block by certain agreed though any assignment of these concessions is subject to the prior factors. See “-Item 4. Information on the Company-B. Business overview-Our operations-Operations in Peru-Morona Block.” authorization by the executive branch of the incumbent Provincial State. For the four years prior to the expiration of each of these concessions, the Argentina Overview of exploitation concessions As the concession holder of the Del Mosquito Concession, we are subject to concession holder must provide technical and commercial justifications for leaving any inactive and non-producing wells unplugged. Each of these concessions can be terminated for default in payment obligations and/or breach of material statutory or regulatory obligations. We may also voluntarily numerous restrictions and fees related to hydrocarbon production and relinquish acreage to the Argentine authorities. For example, in November foreign markets. For example, the domestic oil and gas market in Argentina 2012, we voluntarily relinquished approximately 102,500 non-producing has supply privileges favoring the domestic market, to the detriment of the gross acres in the Del Mosquito Block to the Argentine authorities, which export market, including hydrocarbon export restrictions, domestic price relinquishment is currently subject to approval by the authorities of the controls, export duties and domestic market supply obligations. We are also province of Santa Cruz and the completion of certain environmental audits. In subject to certain foreign currency retention restrictions. We must comply addition, in April 2014, we informed the Secretary of Infrastructure and with central bank registration requirements, maintain a minimum one-year Energy of the Province of Mendoza of our decision to relinquish 100% of the residency in Argentina and comply with central bank registration Cerro Doña Juana and Loma Cortaderal Concessions to the Mendoza requirements, including the requirement that 30% of all funds remitted to Province. The area covered by the Cerro Doña Juana and Loma Cortaderal Argentina remain deposited in a domestic financial institution for one year Blocks is 47.9 acres and neither the Cerro Doña Juana nor the Loma without yielding interest unless such funds are proven invested in exploration Cortaderal were in production or have any associated reserves. 104 GeoPark 20F Our Argentine concessions are governed by the laws of Argentina and the drag-along rights, and the non-transferring shareholder has the right to resolution of any disputes must be sought in the Federal Courts, although object to a sale to the third-party if it considers such third-party to be not of provincial courts may have jurisdiction over certain matters. a good reputation or one of our direct competitors. Under the LGI Chile Agreements with LGI LGI Chile Shareholders’ Agreements In 2010, we formed a strategic partnership with LGI to jointly acquire and 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 obligations. See “-Item 3. Key Information-D. develop upstream oil and gas projects in Latin America. In 2011, LGI acquired Risk factors-Risks relating to our business-LGI, our strategic partner in Chile a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark and Colombia, may sell its interest in our Chilean and Colombian operations TdF, for a total consideration of US$148.0 million, plus additional equity to a third party or may not consent to our taking certain actions.” 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 and LGI entered into a shareholders’ agreement (as amended on July 4, 2011, the GeoPark LGI Colombia Agreements In December 2012, we and LGI agreed that we would extend our strategic Chile Shareholders’ Agreement) and a subscription agreement (as amended partnership to build a portfolio of upstream oil and gas assets throughout on July 4, 2011 and October 4, 2011, in connection with LGI’s investment Latin America through 2015. On December 18, 2012, LGI agreed to in GeoPark TdF, the GeoPark TdF Subscription Agreement, and, together acquire a 20% equity interest in GeoPark Colombia for a total consideration with the GeoPark Chile Shareholders’ Agreement, the LGI Chile Shareholders’ of US$20.1 million composed of a US$14.9 million capital contribution, a Agreements), setting forth our and LGI’s respective rights and obligations US$4.9 million loan to GeoPark Colombia and miscellaneous reimbursements. in connection with LGI’s investment in our Chilean oil and gas business. Concurrently, we and LGI entered into a shareholders’ agreement, the LGI Colombia Shareholders’ Agreement, setting forth our and LGI’s respective The respective boards of each of GeoPark Chile and GeoPark TdF supervise obligations in connection with LGI’s investment in our Colombian oil and gas their day-to-day operations. Each of these boards has four directors. As long business, and LGI and Winchester (now GeoPark S.A.S.) entered into a loan as LGI holds at least 5% of the voting shares of GeoPark Chile, LGI has the agreement, whereby, upon the closing of LGI’s subscription of shares in right to elect one director and such director’s alternate, and the remaining GeoPark Colombia, LGI granted a credit line (of which US$4.9 million was directors, and alternates, are elected by us. As long as LGI holds at least drawn at closing) to Winchester (now GeoPark S.A.S.) of up to US$12.0 million, 5% of the voting shares of GeoPark TdF, LGI has the right to elect one director to be used for the acquisition, development and operation of oil and gas and such director’s alternate, and the remaining directors, and alternates, assets in Colombia. Further, on January 8, 2014, following an internal are elected by GeoPark Chile. corporate reorganization of our Colombian operations, GeoPark Colombia Coöperatie U.A. and GeoPark Latin America entered into a new members’ The LGI Chile Shareholders’ Agreements require the consent of LGI or agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out the LGI appointed director in order for GeoPark Chile and GeoPark TdF, as substantially similar rights and obligations to the LGI Colombia Shareholders’ the case may be, to take certain actions, including, among others: • making any decision to terminate or permanently or indefinitely suspend Agreement in respect of our oil and gas business in Colombia. We refer to the LGI Colombia Shareholders’ Agreement and the LGI Colombia Members’ operations in or surrender our blocks in Chile (other than as required under Agreement collectively as the LGI Colombia Agreements. the terms of the relevant CEOP for such blocks); • selling our blocks in Chile to our affiliates; GeoPark Colombia’s board supervises its day-to-day operations. GeoPark • any change to the dividend, voting or other rights that would give Colombia has four directors. As long as LGI holds at least 14% of the voting preference to or discriminate against the shareholders of GeoPark Chile and shares of GeoPark Colombia, LGI has the right to elect one director and GeoPark TdF; such director’s alternate, and the remaining directors and alternates are • entering into certain related party transactions; and elected by us. • creating a security interest over our blocks in Chile (other than in connection with a financing that benefits our Chilean subsidiaries). Under the LGI Colombia Agreements, LGI agreed to assume its share of the existing debt of GeoPark Colombia and to provide additional funding to The LGI Chile Shareholders’ Agreements provide that if LGI or either Agencia cover LGI’s share of required future investments in Colombia. In addition, we or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark can earn back up to 12% additional equity interests in GeoPark Colombia TdF, as the case may be, the transferring shareholder must make an offer to depending on the success of our Colombian operations. sell those shares to the other shareholder before selling those shares to a third party. In addition, any sale to a third party is subject to tag-along and GeoPark 20F 105 The LGI Colombia Agreements require the consent of LGI or the LGI- Chile, the Republic of Chile grants such rights through a CEOP. In Colombia, appointed director for GeoPark Colombia to take certain actions, including, the Republic of Colombia grants such rights through E&P Contracts or among others: contracts of association. In Argentina, the Argentine Republic grants such • making any decision to terminate or permanently or indefinitely suspend rights through exploitation concessions. In Brazil, the Federative Republic operations in or surrender our blocks in Colombia (other than as required of Brazil grants such rights pursuant to concession agreements. See “-Item 3. under the terms of the relevant concessions for such blocks); Key Information-D. Risk factors-Risks relating to the countries in which we • creating of a security interest over our blocks in Colombia; operate-Oil and natural gas companies in Chile, Colombia, Brazil, Peru and • approving of GeoPark Colombia’s annual budget and work programs and Argentina do not own any of the oil and natural gas reserves in such the mechanisms for funding any such budget or program; countries.” Other than as specified in this annual report, we believe that we • entering into of any borrowings other than those provided in an approved have satisfactory rights to exploit or benefit economically from the oil budget or incurred in the ordinary course of business to finance working and gas reserves in the blocks in which we have an interest in accordance capital needs; • granting any guarantee or indemnity to secure liabilities of parties other with standards generally accepted in the international oil and gas industry. Our CEOPs, E&P Contracts, contracts of association, exploitation concessions than those of our Colombian subsidiaries; and concession agreements are subject to customary royalty and other • changing the dividend, voting or other rights that would give preference to interests, liens under operating agreements and other burdens, restrictions or discriminate against the shareholders of GeoPark Colombia; and encumbrances customary in the oil and gas industry that we believe do • entering into certain related party transactions; and not materially interfere with the use of or affect the carrying value of our • disposing of any material assets other than those provided for in an interests. See “-Item 3. Key Information-D. Risk factors-Risks relating to our approved budget and work program. business-We are not, and may not be in the future, the sole owner or operator We have also agreed to ensure that the board of directors and rules and of the working interests in certain of our licensed areas.” Therefore, we may management of our other subsidiaries engaged in our Colombian oil and gas not be able to control the timing of exploration or development efforts, business are subject to the same principles and restrictions outlined above. associated costs, or the rate of production of any non-operated and, to an of all of our licensed areas and do not, and may not in the future, hold all extent, any non-wholly-owned, assets.” The LGI Colombia Agreements provide that if either we or LGI decide to sell our respective shares in GeoPark Colombia, the transferring shareholder must make an offer to sell those shares to the other shareholder before selling Our customers In Chile, our primary customers are ENAP and Methanex. As of December 31, those shares to a third party. In addition, any sale to a third party is subject to 2014, ENAP purchased all of our oil and condensate production and tag-along and drag-along rights, and the non-transferring shareholder has Methanex purchased almost all of our natural gas production in Chile, and the right to object to a sale to the third-party if it considers such third-party to represented 28% and 6%, respectively, of our total revenues for the year be not of a good reputation or one of our direct competitors. ended December 31, 2014. Our contract with ENAP is automatically renewed Under the LGI Colombia Agreements, we and LGI have agreed to vote our for six-month terms, with oil pricing based on international market prices. Our contract with Methanex is a long-term contract, with the price of natural common shares or otherwise cause GeoPark Colombia to declare dividends gas based on the international market prices for methanol. In Colombia, only after allowing for retentions for approved work programs and budgets our primary customers are Gunvor, Emerald and Perenco, who purchase our and capital adequacy requirements of GeoPark Colombia, working capital production through short-term contracts, and who represented 40%, 32%, requirements, banking covenants associated with any loan entered into by and 11%, respectively, of our total revenues for the year ended December 31, GeoPark Colombia or our other Colombian subsidiaries and operational 2014. In Brazil, following the Manatí acquisition on March 31, 2014, all of requirements. See “-Item 3. Key Information-D. Risk factors-Risks relating to our hydrocarbons are sold to Petrobras. In Peru, our primary customer may our business-LGI, our strategic partner in Chile and Colombia, may sell its be Petroperú, who has the first option but not the obligation to purchase interest in our Chilean and Colombian operations to a third party or may not oil produced by us in the Morona Block. consent to our taking certain actions.” Title to properties In each of the countries in which we operate, the state is the exclusive owner Seasonality Although there is some historical seasonality to the prices that we receive for our production, the impact of such seasonality has not been material. of all hydrocarbon resources located in such country and has full authority to Additionally, seasonality does not play a significant role in our ability to determine the rights, royalties or compensation to be paid by private conduct our operations, including drilling and completion activities. Although investors for the exploration or production of any hydrocarbon reserves. In in winter months, it is more difficult or even impossible to conduct certain of 106 GeoPark 20F our operations, such as seismic work, we take such seasonality into account Health, safety and environmental matters in planning for and conducting our operations, such that the impact on our overall business is not material. General We and our operations are subject to various stringent and complex international, federal, state and local environmental, health and safety laws Our competition The oil and gas industry is competitive, and we may encounter strong and regulations in the countries in which we operate governing matters including the emission and discharge of pollutants into the ground, air or competition from other independent operators and from major oil companies water; the generation, storage, handling, use and transportation of regulated in acquiring and developing licenses. In Chile, we partner with and sell to, materials; and human health and safety. These laws and regulations may, and may from time to time compete with, ENAP and, to a lesser extent, some among other things: companies with operations in Argentina mentioned below. In Colombia, • require the acquisition of various permits or other authorizations or the we partner with and sell to, and may from time to time compete with, preparation of environmental assessments, studies or plans (such as well Ecopetrol, as well as with privately-owned companies such as Pacific Rubiales, Gran Tierra, Petrominerales, Parex and Canacol, among others. In Brazil, we closure plans) before seismic or drilling activity commences; • enjoin some or all of the operations of facilities deemed not in compliance partner with and sell to, and may from time to time compete with, Petrobras, with permits; privately-owned companies such as HRT, QGEP, Brasoil and some of the • restrict the types, quantities and concentration of various substances that Colombian companies mentioned above, which have entered into Brazil, can be released into the environment in connection with oil and natural gas among others. In Argentina, we compete for resources with YPF, as well drilling, production and transportation activities; as with privately-owned companies such as Pan American Energy, Pluspetrol, • require establishing and maintaining bonds, reserves or other commitments Tecpetrol, Chevron, Wintershall, Total, Sinopec and others. In Peru, we will to plug and abandon wells; partner with and will sell to, Petroperú and will compete for resources with • limit or prohibit seismic and drilling activities in certain locations lying privately-owned companies such as Pluspetrol, Gran Tierra, Repsol, Graña within or near protected or otherwise sensitive areas; and y Montero, Hunt Oil, Olympic Oil & Gas, Savia, among others; and with state- • require remedial measures to mitigate or remediate pollution from our owned oil companies as CNPC (China National Petroleum Corporation). operations, which, if not undertaken, could subject us to substantial penalties. Many of these competitors have financial and technical resources and These laws and regulations may also restrict the rate of oil and natural personnel substantially larger than ours. As a result, our competitors may be gas production below the rate that would otherwise be possible. Compliance able to pay more for desirable oil and natural gas assets, or to evaluate, bid with these laws can be costly. The regulatory burden on the oil and gas for and purchase a greater number of licenses than our financial or personnel industry increases the cost of doing business in the industry and resources will permit. Furthermore, these companies may also be better consequently affects profitability. able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally Moreover, public interest in the protection of the environment continues adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and to increase. Drilling in some areas has been opposed by certain community and environmental groups and, in other areas, has been restricted. regulations, which may adversely affect our competitive position. See “-Item Our operations could be adversely affected to the extent laws are enacted 3. Key Information-D. Risk factors-Risks relating to our business-Competition or other governmental action is taken that prohibits or restricts seismic or in the oil and natural gas industry is intense, which makes it difficult for drilling activities or imposes environmental requirements that result in us to acquire properties and prospects, market oil and natural gas and secure increased costs to the oil and gas industry in general, such as more stringent trained personnel.” or costly waste handling, disposal or cleanup requirements. We are also affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand Climate change Our operations and the combustion of oil and natural gas-based products for drilling rigs, supplies, services, equipment and crews, and can lead to results in the emission of greenhouse gases, which may contribute to global shortages of, and increasing costs for, drilling equipment, services and climate change. Climate change regulation has gained momentum in personnel. Over the past several years, oil and natural gas companies have recent years internationally and at the federal, regional, state and local levels. experienced higher drilling and operating costs. Shortages of, or increasing On the international level, various nations have committed to reducing costs for, experienced drilling crews and equipment and services could their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto restrict our ability to drill wells and conduct our operations. Protocol was set to expire in 2012. In late 2011, an international climate change conference in Durban, South Africa resulted in, among other things, GeoPark 20F 107 an agreement to negotiate a new climate change regime by 2015 that would Chilean government, through the Superintendency of the Environment, aim to cover all major greenhouse gas emitters worldwide, including the to: (1) bring administrative and judicial proceedings against companies U.S., and take effect by 2020. In November and December 2012, at an that violate environmental laws; (2) close non-complying facilities; (3) revoke international meeting held in Doha, Qatar, the Kyoto Protocol was extended required operating licenses; and (iv) impose sanctions and fines when by amendment until 2020. In addition, the Durban agreement to develop companies act negligently, recklessly or deliberately in connection with the protocol’s successor by 2015 and implement it by 2020 was reinforced. environmental matters. Other regulation of the oil and gas industry Chile Companies in the oil and gas sector, like all Chilean companies, must comply The sanction procedures and environmental liability claims derived from environmental damage will be handled by the Chilean environmental court. with the general principles concerning employee health and safety laws that For additional information on environmental, health and safety regulations are contained in the Chilean Labor Code and other labor statutes. The Chilean applicable to the Chilean oil and gas sector, see “-Industry and regulatory Ministry of Labor is responsible for the enforcement of those standards, with framework-Chile-Regulatory entities.” the authority to impose fines. In addition, the Health Department of the Ministry of Health has the responsibility to monitor compliance and also the authority to impose fines and stop operations of health and safety violators. Colombia Health, safety and environmental regulation of the oil and gas industry in Colombia is dispersed throughout a number of different laws and regulations. Regarding environmental matters, the Chilean Constitution grants all Environmental regulation is primarily governed by Law 99 of 1993, which citizens the right to live in a pollution-free environment. It further provides established the Ministry of Environment and provided for the issuance that other constitutional rights may be limited in order to protect the of a number of associated laws and regulations. The Ministry of Environment environment. Chile has numerous laws, regulations, decrees and municipal through the ANLA monitors compliance with environmental obligations. ordinances relating to environmental protection, pursuant to which specific Furthermore, licenses for exploration and exploitation of hydrocarbons approvals, consents and permits may be required in order to perform are granted by the ANLA and this is the entity in charge of monitoring the activities that may affect the environment. permits. Regional corporations who are responsible for monitoring environmental compliance within their regions have additional obligations. The General Environmental Law (Law No. 19,300), enacted in March 1994 and modified in 2010 by Law No. 20,417, establishes a framework for Law 99 introduced the requirement of environmental permits for activities, environmental regulation in Chile, which has become increasingly stringent including oil and gas exploration and production, which can cause serious in recent years. Recent amendments include, among others, the creation deterioration of renewable natural resources or damage to the environment, of a new institutional framework composed of: (1) the Ministry of or that introduce substantial changes to the landscape. Decree 2820 of 2010 Environment (Ministerio del Medio Ambiente); (2) the Council of Ministers for requires an environmental license for all hydrocarbon projects, including Sustainability (Consejo de Ministros para la Sustentabilidad); (3) the Environmental Assessment Agency (Servicio de Evaluación Ambiental); and for each of the following activities: conducting seismic exploration activities that require the construction of roads for vehicular traffic, exploratory drilling (4) the Superintendency of the Environment (Superintendencia del Medio projects, exploitation of hydrocarbons and development of related facilities Ambiente), all of which are in charge of regulating, assessing and enforcing (including internal pipelines and storage, roads and related infrastructure), activities that could have an environmental impact. Recent modifications transportation and handling of liquid and gaseous hydrocarbons, developing introduced to existing regulations also gives right for public participation liquid hydrocarbon delivery terminals or transfer stations, and construction for interested people and non-governmental organizations in the assessment and operation of refineries. Other hydrocarbon activities may require of projects, which could result in additional delays for the final approval of environmental permits as well. Compliance with environmental regulations new projects. is handled under a strict sanctioning regime, established by Law 1333 of 2009, whereby liability is presumed and fines are significant. The new institutions and regulatory framework are likely to result in additional restrictions or costs on us relating to environmental litigation and Legislation governing Health and Safety is varied, but mainly focuses on the protection of the environment, particularly those related to plant and animal Law 1562 of 2012, issued by the Colombian Congress through the System life, wildlife protected areas, water quality standards, air emissions and soil of Occupational Hazards. pollution. In addition, violations of these environmental regulations may lead to fines, the closure of facilities and the revocation of environmental Law 1010 of 2006 established actions to prevent, correct and punish labor approvals. The General Environmental Law and its regulations entitle the bullying; Resolution 2646 of 2008 of the Ministry of Health and Social 108 GeoPark 20F Protection establishes responsibilities for the identification, assessment, CONAMA Resolution No. 350/2004 governs environmental licensing for prevention, intervention and ongoing monitoring of exposure to psychosocial seismic activities. Ordinance No. 422, from October 26, 2011, issued by the risk factors at work and for determining the origin of defined diseases Brazilian Ministry for the Environment, sets forth rules for the environmental caused by occupational stress; among others. licensing of: (1) seismic activities (i.e., clarifying and creating some new steps between those mentioned above); (2) drilling; and (3) oil and gas For additional information on environmental, health and safety regulations production and evacuation, as well as Extended Well Tests, or EWTs. For the applicable to the Colombian oil and gas sector, see “-Industry and regulatory environmental licensing of oil and gas production and evacuation, as well framework-Colombia-Regulatory entities.” as EWTs, the proceeding is more complex. The steps differ depending on the Brazil In accordance with Brazilian environmental legislation, activities or ventures for the installation of the enterprise, which needs a Preliminary License (Licença Prévia), or LP; (2) implementation and installation of the project that use natural resources or that are deemed to be actually or potentially licensed with the LP, which needs an Installation License (Licença de polluting are subject to environmental licensing requirements, under which the Instalação) or LI; and (3) operation of the enterprise installed according with relevant environmental body analyzes location, facilities, expansion and the LI, which needs an Operation License (Licença de Operação). operation of projects, as well as establishes conditions for project development. status of the enterprise and the environmental license sought: (1) planning The environmental licensing of oil and natural gas exploration, development Environmental licensing of E&P activities in the offshore basin (territorial and production activities is subject to, among several other requirements, sea, the continental platform and exclusive economic zones) is granted on the preparation of environmental assessments, the complexity and rules a federal level. The environmental licensing in Brazil may be subject to of which vary according to the activities sought, the depth and distance from federal, state or municipal (local) licensing as a general rule, and in many the coast and the environmental sensitivity of the area in which the industries it is usual to have projects in which more than one of those development of activities is sought. Among such studies, the Environmental entities claim jurisdiction. That may be the case for onshore E&P activities Impact Assessment (Estudo Prévio de Impacto Ambiental) and the respective (and it is in the ports sector, for instance), but such controversy does not Environmental Impact Report (Relatório de Impacto de Ambiental) may be apply to offshore E&P environmental licensing. deemed the most complex and time-demanding environmental assessment, The IBAMA, by means of its General Supervision for Oil and Gas Licensing an Environmental Drilling Study (Estudio Ambiental de Perfuração) may also (Coordenação Geral de Licenciamento de Petróleo e Gás), is the entity in be required for purposes of respective environmental licensing. This is a very charge of the environmental licensing for E&P projects. comprehensive, tailor-made analysis of the environmental impacts, to be though an Environmental Seismic Study (Estudio Ambiental de Sísmica) or produced by the enterprise. E&P activities are divided in two subgroups, according to the Brazilian Ministry for the Environment: (i) seismic activities; and (ii) drilling As a compensatory measure, we are also obligated to allocate funds for and production of hydrocarbons. In addition to the Complementary Law, the main rules governing the environmental licensing of such activities the implementation and maintenance of conservation areas, based on Federal Law No. 9,985/2000, which are evaluated by the competent are: (1) Resolution No. 237, from December 19, 1997, issued by the Brazilian environmental agency on the basis of Federal Decree Nos. 4,340/2002 and National Committee for the Environment (Conselho Nacional do Meio- 6,848/2009 and which must not exceed the value of 0.5% of the total cost Ambiente), or CONAMA; (2) Resolution No. 350, from July 6, 2004, also issued involved for the construction of the facility. by CONAMA; and (3) Ordinance No. 422, from October 26, 2011, issued by the Brazilian Ministry for the Environment. Failure to maintain a valid environmental license is classified as an administrative infraction and environmental crime. Any delays or denials CONAMA Resolution No. 237 sets forth the general rules that must be by the environmental licensing authority in issuing or renewing licenses, complied with regarding environmental licensing. It prescribes that the as well as the inability to meet the requirements established by the competent environmental authority, with the entrepreneur’s participation, environmental authorities during the environmental licensing process, may shall define the plans, projects and environmental assessments necessary harm or even prevent the construction and regular development of the to start the environmental licensing proceeding. In addition, IBAMA activity. Some environmental licenses related to operation of the Manatí Normative Ordinance No. 184, from July 17, 2008, defines the general rules Field production system and natural gas pipeline are expired. However, of environmental licensing on the federal level. However, for oil and the operator submitted, timely, the request for renewal of those licenses and gas activities, these general rules do not apply and have been adjusted as such this operation is not in default as long as the regulator does not and regulated by specific regulation, as mentioned below. state its final position on the renewal. GeoPark 20F 109 Environmental nonconformities and damages may result in civil, Due to environmental damages and noncompliance with environmental administrative and criminal liabilities. laws and regulations, the environmental authorities may also propose Conduct Adjustment Agreements (Termos de Ajustamento de Conduta) The National Environmental Policy (Federal Law No. 6,938/81) regulates civil through which the enterprise may be obliged to fund recovery works and liability for damages caused to the environment, such liability being of an environmental projects. objective nature (strict liability), i.e., irrespective of fault. Demonstration of the cause-effect relationship between damage caused and action or inaction For additional information on environmental, health and safety regulations suffices to trigger the obligation to redress environmental damage. The fact applicable to the Brazilian oil and gas sector, see “-Industry and regulatory that the relevant entity’s operations are covered by environmental licenses framework-Brazil-Regulatory entities.” does not preclude such liability. The National Environmental Policy established joint liability among polluting agents. In case of environmental damage to an industrial area, it may be difficult to identify the source of Peru In accordance with Peruvian environmental legislation, before initiating any environmental damages and intensity thereof. The victim of such damages hydrocarbon activity (e.g. seismic exploration, drilling of exploration wells, etc.) or whomever the law so authorizes, as indicated below, is not compelled the contractor must file and obtain an approval for an environmental impact to sue all polluting agents within the same proceeding. Because liability is of study, which is a significant permit related to HSE for any hydrocarbon project. a joint nature, the aggrieved party may choose one out of all polluting This study includes technical, environmental, and social evaluations of the agents (for example, the agent with the best economic standing) to redress project to be executed in order to define the activities that should be required all damages. A polluting agent so sued will have a right of recourse against for preventing, minimizing, mitigating and remediating the possible negative the other polluting agents. environmental and social impact that hydrocarbon activities may generate. Furthermore, under Brazilian law, due to environmental damages and The competent authority for protection and environmental conservation noncompliance with environmental laws and regulations, individuals or in the case of hydrocarbon activities is the Ministry of Energy and Mines, entities are also subject to criminal and administrative sanctions. through the General Bureau of Energetic Environmental Affairs (Dirección General de Asuntos Ambientales - DGAA). In the criminal sphere, the Environmental Crimes Act (Federal Law No. 9,605/98) applies to every individual or legal entity that carries out any There are also some additional environmental permits that should be activity deemed damaging to the environment. Because criminal liability obtained by GeoPark before starting any hydrocarbon activity in the Block. is of a subjective nature, the Environmental Crimes Act attributed liability to These environmental permits are typically requested shortly after the representatives of legal entities. As a result, upon occurrence of an approval of the environmental impact assessment. environmental violation, a legal entity’s officer, administrator, director, manager, agent or attorney-in-fact may also be subject to criminal penalties, Health and Safety Management at work is regulated by Law 29,783, which which comprise fines and imprisonment. With respect to judicial actions, a civil or administrative settlement does not prevent prosecution in a criminal constitutes the basis for regulatory compliance across both public and private industries. The purpose of this regulation is to foster and promote the sphere should an environmental crime have occurred. prevention of workplace hazards and establish minimum guidelines to be In the administrative sphere, Federal Decree No. 6,514/2008 provides that be managed taking into consideration the compliance with local regulations implemented within organizations. Therefore, health and safety issues should environmental authorities may also impose administrative sanctions for those and best practices across the industry. who do not comply with environmental laws and regulations, including, among others: simple fines from R$50 to R$50 million, depending on the The Peruvian government has enacted several environmental regulations infraction, e.g., absence of environmental licenses or failure to comply with regarding not only hydrocarbon activities but also in relation to waste its terms may subject the entrepreneur to a fine ranging from R$500 to treatment, water use, natural protected areas, biodiversity protection, etc. R$10 million, daily fines, partial or total suspension of activities, demolition For additional information on environmental, health and safety regulations of the enterprise and rights restriction sanctions, such as forfeiture or applicable to the Peruvian oil and gas sector, see “-Industry and regulatory restriction of tax incentives or benefits, closing of the establishments or framework-Peru-Regulatory entities.” ventures and forfeiture or suspension of participation in credit lines with official credit establishments. For additional information on environmental, health and safety regulations applicable to the Peruvian oil and gas sector, see “-Industry and regulatory framework-Peru-Regulatory entities.” 110 GeoPark 20F Argentina Historically, environmental legislation and enforcement powers in respect Our policy is to strive to meet or exceed environmental regulations in the countries in which we operate. We believe that oil and gas can be produced of oil and gas operations have been vested with the federal government. in an environmentally-responsible manner with proper care, understanding However, after the 1994 constitutional reform and after the enactment of the and management. We have within our S.P.E.E.D. program a team that YPF Privatization Law in 1992, provincial states have passed and enforced is exclusively focused on securing the environmental authorizations concurrent new environmental legislation. The federal government is and permits for the projects we undertake. This team is also responsible for empowered to establish minimum environmental protection standards and the achievement of the environmental standards set by our board of provincial governments are empowered to complement them, though directors and for training and supporting our personnel. In these activities, provincial environmental legislation is not always fully consistent with federal we are supported by experienced oil and gas environmental consulting environmental legislation. firms. Our senior executives have also received training in proper environmental management. The oil and natural gas industry in Argentina is subject to environmental regulations pursuant to concurrent provincial state and federal legislation. Such legislation provides for restrictions and prohibitions on the release or Our health and safety policy We believe that the implementation of additional safety tools in our emission of various substances produced in association with certain oil operations in 2012 have significantly contributed to control and minimizing and gas industry operations. In addition, such legislation requires that wells, risks in our operation. Actions taken by us included training, permits to work, facilities and sites be abandoned, reclaimed and/or remediated according internal audits, drills, tailgate safety meetings, job safety analysis and risk to specific standards and/or to the satisfaction of governmental authorities evaluations. As of December 31, 2014, on the last 12-month basis, our HSE and/or surface owners. Compliance with such legislation can require development statistics shows that Lost Time Injury Frequency (LTIF) was significant expenditures and a breach of such requirements may result in 0.75 and our Total Recordable Incident Rate (TRIR) was 1.8 (every 1.000,000 suspension or revocation of necessary licenses and authorizations, civil worked hours) compared to 3.1 and 4.75, from 2013 respectively. We and criminal liability for pollution damage and the imposition of material had no workforce-related fatal incidents related to work operations in 2014. fines and penalties. Environmental regulations in Argentina also require that wells be plugged Certain Bermuda law considerations As a Bermuda exempted company, we and our Bermuda subsidiaries are in and that facility sites be abandoned and returned to Argentina in a state subject to regulation in Bermuda. We have been designated by the Bermuda deemed satisfactory to the applicable regulatory authorities. Four years prior Monetary Authority as a non-resident for Bermuda exchange control to the expiration of any hydrocarbon concession granted by the Argentine purposes. This designation allows us to engage in transactions in currencies government, an operator is required to present any technical or commercial other than the Bermuda dollar, and there are no restrictions on our ability reasons for seeking to leave an inactive and non-producing well unplugged to transfer funds (other than funds denominated in Bermuda dollars) in and to the applicable regulatory authorities. In addition, the province of out of Bermuda. Santa Cruz, in which the Del Mosquito Block is located, has created a Registry of Environmental Liabilities and requires operators to submit a five-year Under Bermuda law, “exempted” companies are companies formed for remediation program for all environmental liabilities that have been registered. the purpose of conducting business outside Bermuda from a principal place of business in Bermuda. As exempted companies, we and our Bermuda For additional information on environmental, health and safety regulations subsidiaries may not, without a license or consent granted by the Minister applicable to the Argentine oil and gas sector, see “-Industry and regulatory of Finance of Bermuda, participate in certain business transactions, including framework-Argentina-Regulatory entities.” transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we or our Bermuda subsidiaries are not Our environmental policy Our health, safety and environmental management plan is focused licensed in Bermuda. on undertaking realistic and practical programs based on recognized world practices. Our emphasis is on building key principles and company-wide Insurance We maintain insurance coverage of types and amounts that we believe ownership and then expanding programs from within as we continue to be customary and reasonable for companies of our size and with similar to grow. Our S.P.E.E.D. program has been developed in accordance with: ISO operations in the oil and gas industry. However, as is customary in the 14001 for environmental management issues, OHSAS 18001 for occupational industry, we do not insure fully against all risks associated with our business, health and safety management issues, SA 8000 for social accountability and either because such insurance is not available or because premium costs workers’ rights issues and applicable World Bank standards. are considered prohibitive. GeoPark 20F 111 Currently, our insurance program includes, among other things, construction, fire, vehicle, technical, umbrella liability, director’s and officer’s liability and employer’s liability coverage. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. A loss not fully covered by insurance could have a materially adverse effect on our business, financial condition and results of operations. See “-Item 3. Key Information-D. Risk factors-Risks relating to our business-Oil and gas operations contain a high degree of risk and we may not be fully insured against all risks we face in our business.” Industry and regulatory framework Global oil and gas industry During 2013, global consumption and production increased for all fuels, reaching record levels for every fuel type except nuclear power. For each of Distribution of proved oil reserves in 1993, 2003 and 2013 Percentage Middle East Europe & Eurasia S. & Cent. America Africa North America Asia Pacific 7.7 2.5 47.9 3.0 55.9 8.0 8.8 13.6 3.7 5.9 63.6 8.7 16.9 7.5 11.6 7.7 7.5 19.5 1993 - Total 1041.4 thousand million barrels 2003 - Total 1334.1 thousand million barrels 2013 - Total 1687.9 thousand million barrels the fossil fuels global consumption rose more rapidly than production. Source: BP Statistical Review Global oil consumption grew by 1.4 million bpd, or 1.4% -just above the According to the BP Statistical Review, world proved natural gas reserves historical average. Global oil production did not keep pace with the growth in at year-end 2013 stood at 185.7 trillion cubic meters (tcm), sufficient to meet global consumption, rising by just 550,000 bpd or 0.6%. The U.S. recorded the 55.1 years of global production. Proved reserves grew by 0.2% relative to largest growth in the world and the largest annual increase in the country’s year-end 2012 data. An increase in the US (+7.1%) accounted for all of the net history for a second consecutive year, according to the BP Statistical Review growth in global proved reserves in 2013. Iran (33.8 tcm) and Russia of World Energy June 2014, or the BP Statistical Review. (31.3 tcm) hold the largest proved reserves. World natural gas consumption grew by 1.4% in 2013, below the historical average of 2.6%. Global natural gas production grew by 1.1%, which was well below the 10-year average of 2.5%. Growth was below average in all regions except Europe and Eurasia. The U.S. (+1.3%) remained the world’s leading producer, but both Russia (+2.4%) and China (+9.5%) recorded larger growth increases in 2013. Nigeria (-16.4%), India (-16.3%), and Norway (-5%) recorded the largest decreases in production. Total world proved oil reserves reached 1687.9 billion barrels at the end of 2013, sufficient to meet 53.3 years of global production. The largest additions to reserves came from Russia, adding 900 million barrels and Venezuela adding 800 million barrels. OPEC members continue to hold the majority of reserves, accounting for 71.9% of the global total. South & Central America continues to hold the highest R/P ratio. Over the past decade, global proved Distribution of proved natural gas reserves in 1993, 2003 and 2013 Percentage Middle East Africa Europe & Eurasia North America Asia Pacific S. & Cent. America 6.3 4.1 43.2 4.7 4.4 8.9 46.5 7.6 8.2 7.4 4.6 37.5 8.1 27.4 30.5 8.5 7.8 34.2 1993 - Total 118.4 trillion cubic metres 2003 - Total 155.7 trillion cubic metres 2013 - Total 185.7 trillion cubic metres reserves have increased by 27%, or over 350 billion barrels. Source: BP Statistical Review 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 growth of US tight oil in recent years has had a dramatic impact, with oil increasingly flowing from West to East rather than East to West. This is likely to continue, with strong growth in China and India driving energy demand. According to the BP Statistical Review, it is also expected that the market in gas will become more global as liquefied natural gas integrates regional markets and leads to greater congruence in global price movements. 112 GeoPark 20F Second, the energy mix continues to shift. Fossil fuels are projected to Natural gas consumption grew significantly from the late 1990s to 2004, as provide the majority of the world’s energy needs, meeting two-thirds direct pipeline connections were built to Argentina, providing a cheap and of the increase in energy demand out to 2035. However, the mix will shift. easily accessible supply. In 2002, however, the Argentine government capped Renewables and unconventional fossil fuels will take a larger share, the price of gas in its domestic market, resulting in increased demand along with gas, which is set to be the fastest growing fossil fuel, as well as for natural gas in Argentina. This led the Argentine government in 2004 to the cleanest, meeting as much of the increase in demand as coal and restrict natural gas exports to Chile in order to reserve them for domestic use. oil combined. See “-Item 3. Key Information-D. Risk factors-Risks relating to the countries in which we operate-governmental actions in the countries in which we Chile Chile is recognized as the most developed and stable economy in South operate and in which we may operate in the future may adversely affect our business, financial condition and results of operations.” The restriction of America. The country’s economy has grown consistently during the last Argentine natural gas exports has caused gas consumption in Chile to two decades, a trend which is expected to continue in the near future. With decrease significantly since 2004, when natural gas accounted for some 24% over 50 free trade agreements, Chile is an open-market economy, and in of the Total Primary Energy Supply, or TPES, according to the International 2010, became the first South American country to join the Organization for Energy Agency. By 2009, natural gas only accounted for 8% of TPES. Economic Co-operation and Development, or the OECD. Chile holds investment-grade sovereign debt ratings from all major ratings agencies, LPG has been consumed in place of natural gas. As such, the LPG and S&P, Fitch and Moody’s (AA-, A+, and Aa3, respectively). gas markets overlap in Chile. LPG is predominantly used as a residential fuel in Chile (notably for cooking), particularly in relatively remote regions. Oil and gas industry Demand and consumption According to ENAP, national consumption of refined oil products reached In 2013, the bulk of gas demand (51%) came from the power generation sector. Industry and the petrochemical sector accounted for 11%, and the 18.45 mmcf in Chile during 2013, a 0.3% increase compared to 2012 and residential/commercial sector for the remaining 13%. equivalent to 317,930 barrels per day. This increase was mainly due to strong and stable economic growth, offset by an increase in prices of the main products. As is the case in many OECD countries, oil is predominantly used as Supply and production Chile is a large net importer of both crude oil and oil products. Its a transport fuel, but a notable difference in Chile is that diesel is used as a hydrocarbon reserves, which comprise limited crude oil reserves and substitute for natural gas in power generation. 1,435 bcf of natural gas reserves according to the OPEC Annual Statistical Bulletin 2014, or the OPEC Bulletin, are concentrated in the Magallanes Diesel is the main product in terms of consumption in Chile, followed by Basin at the southern tip of the country. gasoline and liquid petroleum gas, or “LPG.” Among the different types of refined oil products, LPG experienced the greatest increase in terms of Due to its limited oil and natural gas reserves, Chile has in the past imported consumption, with consumption increasing 6.4% compared to 2012. almost all of its crude oil requirements principally from Brazil, Argentina and Colombia, and most of its natural gas requirements principally from Consumption in Chile by type of oil product (thousands of cubic meters) Diesel Gasoline LPG Fuel Oil Kerosene Others Total Source: ENAP 2013 Annual Report 2013 9,183 4,024 2,244 1,174 1,331 496 2012 9,153 3,856 2,109 1,498 1,243 542 18,452 18,401 % change Trinidad and Tobago, Argentina, Guinea and Yemen. In the northern part of from the country, natural gas is imported through the Mejillones liquid natural prior year gas, or LNG, terminal and is used predominantly for electricity generation by the mining industry. In the central part of the country (including the capital, Santiago), gas is primarily supplied by the Quintero LNG terminal. 0.3% 4.4% 6.4% -21.6% 7.1% -8.5% 0.3% GeoPark 20F 113 Oil and Gas Infrastructure in Chile OIL Oil Products pipeline Crude Oil pipeline Refinery GAS Existing pipelines Gas Fields Existing LNG import terminal Regasification plants P E RU Arica B OLI V I A B OLI V I A PE RU Arica Tocopilla Mejillones Antofagasta Taltal Quintero Con Con Santiago Quintero Santiago Bio Bio Concepción A R GE NTI NA Concepción AR GE NTI NA C H IL E Gregorio Punta Arenas Pemuco C H IL E Punta Arenas are nonetheless subject to significant government regulations, such as regulations concerning the environment, tort liability, health and safety and labor. In the past year, for example, the Chilean government has proposed new regulations regarding the closure plans applicable to hydrocarbon operations that could have an impact on the timeframes and costs required to set up exploration or exploitation activities. Regulatory entities The Chilean Ministry of Energy and the National Commission of Energy (Comisión Nacional de Energía), or the CNE, are the principal government agencies responsible for the issuance of policies and regulations for the oil and gas sector. The Chilean Ministry of Energy is responsible for monitoring a participant’s compliance with its obligations under a CEOP. The Superintendency of Electricity and Fuels (Superintendencia de Electricidad y Combustibles), or the SDEC, supervises compliance with regulations regarding gas pipeline transportation and the Ministry of Environment, the Environmental Assessment Agency and the Superintendency of Environment are responsible for environmental matters. The new Environmental Courts are responsible for settling disputes relating to environmental permits, claims against the Superintendency of Environment and claims concerning environmental damage. In 2013, Chile produced 6.9 mbopd of crude oil and 965 million cubic meters Ministry of Energy The Chilean Ministry of Energy is responsible for developing and of natural gas but imported 179.6 mbopd of crude oil and 137.3 bcf of natural coordinating all plans, policies and regulations for the energy sector in Chile gas, according to the Chilean Ministry of Energy. and supervising and advising the government in all matters related to energy. It coordinates the different entities in the energy sector in Chile and, The exploration and development of oil fields in Chile has historically been by law, its Minister is the chairman of the board of directors of ENAP. The controlled mainly by ENAP, with few private companies working in this sector. Ministry of Energy is also responsible for the protection, conservation and We were the first private producer of oil and gas in Chile. development of renewable and non-renewable energy resources. Regulation of the oil and gas industry Under the Chilean Constitution, the state is the exclusive owner of all mineral SDEC The SDEC is responsible for monitoring compliance with all regulations and fossil substances, including hydrocarbons, regardless of who owns the related to the generation, production, storage, transportation and distribution land on which the reserves are located. The exploration and exploitation of all fuels, gas and electricity for the consumer market. To enforce such of hydrocarbons may be carried out by the state, companies owned by the regulations, the SDEC has the power to impose fines and, if necessary, to take state or private entities through administrative concessions granted by over the administration of deficient services when applicable. Our operations the President of Chile by Supreme Decree or CEOPs executed by the Minister are not under the supervision of the SDEC. of Energy. Exploitation rights granted to private companies are subject to special taxes and/or royalty payments. The hydrocarbon exploration and Ministry of Environment, Environmental Assessment Agency and Superintendency exploitation industry is supervised by the Chilean Ministry of Energy. of Environment The Ministry of Environment, the Environmental Assessment Agency and the In Chile, a participant is granted rights to explore and exploit certain assets Superintendency of Environment are primarily responsible for environmental under a CEOP. If a participant breaches certain obligations under a CEOP, issues in Chile, including those affecting the oil and gas industry. The Ministry the participant may lose the right to exploit certain areas or may be required of Environment is responsible for the formulation and implementation to return all or a portion of the awarded areas to Chile with no right of of environmental policies, plans, programs and regulation, as well as for the compensation. Although the government of Chile cannot unilaterally modify protection and conservation of biological diversity and renewable natural the rights granted in the CEOP once it is signed, exploration and exploitation resources and water resources and for promoting sustainable development 114 GeoPark 20F and the integrity of environmental policy and regulations. The Environmental landowner through judicial process. Pursuant to the Chilean Code of Mines, Assessment Agency is responsible for assessing whether projects that a judge can permit a party to use an easement pending final adjudication and might have an adverse effect on the environment comply with Chilean settlement of compensation for the affected landowner. environmental laws and regulations. The Environmental Assessment Agency directs and coordinates the environmental impact assessment process, whose final qualification is granted by the competent regional Regulation of transportation activities Liquid hydrocarbon transportation, storage, importation and marketing environmental assessment commission. The Superintendency of are subject to a number of technical regulations regarding safety, quality and Environment’s primary responsibilities are monitoring compliance with the other matters. The rules for the transportation of liquid fuels through terms of an environmental impact assessment, as well as monitoring trucks and pipelines are primarily found in Supreme Decree No. 160 of 2009 compliance with government plans to prevent environmental damage or (the Safety Code for Facilities and Production and Refining Operations, to clean or restore contaminated geographical areas. The Superintendency Transportation, Storage, Distribution and Supply of Liquid Fuels) of the of Environment has the power to suspend or terminate, or impose fines Ministry of Economy. The Ministry of Energy is responsible for the regulation from US$1,000 up to US$10.0 million for, activities that it deems to have an of transportation by pipeline and the Ministry of Transport is responsible for adverse environmental impact, even if such activities comply with a the regulation of transportation by truck. previously approved environmental impact assessment. Gas transportation in Chile is subject to open access rules, in which the gas The Environmental Courts The Environmental Courts are principally responsible for hearing appeals of transportation company must make its excess transportation capacity available to third parties under equal economic, commercial and technical decisions made by the Superintendency of Environment and for adjudicating conditions. Laws prohibit the abuse of a dominant position by a gas claims for environmental damage. There are currently two Environmental transportation company in order to discriminate among potential customers Courts in Chile, which began to hear claims on December 28, 2012 and on for use of its pipelines. Pursuant to Ministry of Economy Supreme Decree October 7, 2013, respectively. There is a third Environmental Court expected No. 280 of 2009, gas pipelines must also comply with the Regulation to begin hearing claims during 2016. The Environmental Court that will of Security for Transportation and Distribution of Gas, which regulates the have jurisdiction over the area in which we operate elected its members on design, construction, operation, maintenance, inspection and termination September 12, 2013 and began its operations in October, 2013. of operations of a natural gas pipeline. Regulatory framework Regulation of exploration and production activities Oil and gas exploration and development is governed by the Political Additionally, Chile is a signatory state to the Substitute Protocol of the Eighth Additional Protocol to the Economic Complementation Agreement No. 16 between Chile Republic and Argentina Republic (ACE 16) Regulation Constitution of the Republic of Chile and Decree with Law Force No 2 of for Marketing, Operations and Transportation of Hydrocarbons Liquids-Crude 1986 of the Ministry of Mines, which set forth the revised text of the Decree Oil, Liquefied Gas and Liquid Products of Petroleum and Natural Gas and Law 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 following international conventions: the International Convention for the prevention of Pollution of the Sea by Oil of 1954, the Convention on the contractors. The CEOP establishes the legal framework for hydrocarbon Prevention of Marine Pollution by Dumping of Wastes and Other Matters of activities, including, among other things, minimum investment commitments, 1972 and the International Convention on Civil Liability for Oil Pollution exploration and exploitation phase durations, compensation for the Damage of 1969. private company (either in cash or in kind) and the applicable tax regime. Accordingly, all the provisions governing the exploitation and development of our Chilean operations are contained in our CEOPs and the CEOPs Taxation With regard to direct taxes on hydrocarbon exploitation, the general rule constitute all the licenses that we need in order to own, operate, import and is that hydrocarbons are transferred to the contractor (its retribution under export any of the equipment used in our business and to conduct our gas the CEOP), and those re-acquisitions from the contractor performed by and petroleum operations in Chile. Chile or its enterprises, as well as their corresponding acts, contracts and documents, are tax exempt. In addition, hydrocarbon exports by the Under Chilean law, the surface landowners have no property rights over contractor are also tax exempt. With regard to income taxes, as provided the minerals found under the surface of their land. Subsurface rights do not by article 5 of Decree Law No. 1,089, the contractor is subject either to a generate any surface rights, except the right to impose legal easements or single tax calculated on its retribution, equal to 50% of such retribution, or to rights of way. Easements or rights of way can be individually negotiated with the general income tax regime established in the Income Tax Law (Decree individual surface land owners or can be granted without the consent of the Law No. 824 of 1974), in force at the time of the execution of the public deed GeoPark 20F 115 which contains CEOPs, terms of which will be applicable and invariable seismic work led to an improvement in the country’s exploratory success throughout the duration of the contract. Income in Chile is subject to rate and, consequently, to a change in the country’s production landscape. corporate tax on an accrual basis and has a current rate of 21% for fiscal year Discoveries in Colombia in general have not been relevant in terms of 2014. The applicable and invariable corporate income tax rates of our CEOPs scale; however, the number of discoveries has favored a significant increase range between 15% and 18.5%, as follows: the Fell Block is subject to a rate in production and the creation of several medium-sized companies. of 15%, the Otway and Tranquilo Blocks are subject to a rate of 17% and Opportunities offered by the Colombian energy sector have changed the the Flamenco, Isla Norte and Campanario Blocks are subject to a rate of 18.5% competitive landscape by attracting foreign investment in the country from for the income accrued or received during 2012 and 17% for the income leading multinational energy companies that operate in Colombia either accrued or received during 2013 and onward. Dividends or profits distributed independently or through joint ventures. to the foreign shareholders of the contractors are subject to 35% Additional Withholding Tax with a tax credit for the corporate income tax paid by According to the BP Statistical Review, Colombia is the third-largest producer the contractor. With regard to the value added tax, contractors may obtain of crude oil and the sixth largest producer of natural gas in Central and South as a refund the value added tax (which is 19% according to the Sales and America. According to the BP Statistical Review, in 2013, the country’s oil Services Tax Law contained in Decree Law No. 825 of 1974) supported or paid production reached 1.004 mmbpd, with natural gas production of 12.6 bcm. on the import or purchase of goods or services used in connection with the exploration and exploitation activities. The applicable tax regime for each Colombia-production profile CEOP remains unchanged throughout the duration of the CEOP. The Chilean Congress approved a reform to the income tax law in September 2014. Under this reform the income tax rate will increase 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 we control in Chile, which are GeoPark TdF S.A., GeoPark Fell S.p.A. and GeoPark Magallanes Limitada, are not affected by the income tax reform mentioned since they are covered by the tax treatment established in the CEOPs. Colombia Oil and gas industry Today, Colombia is one of the largest and most stable economies in South America. The country has a stable political and judicial environment, with a 1092 177 1137 193 1208 204 967 182 840 169 671 786 915 944 1004 1300 1100 900 700 500 300 100 -100 2009 2010 2011 2012 2013 Oil production (mbpd) Gas production (mboepd) Source: BP Statistical Review strong track record of growth. Furthermore, Colombia holds investment- Colombia is divided in 23 sedimentary basins. Colombian sedimentary basins grade sovereign debt ratings from all major rating agencies (BBB, BBB- and Baa2 from S&P, Fitch and Moody’s, respectively). have extensively developed petroleum systems that make them well suited for exploration and exploitation of hydrocarbons. Colombian supply growth In 2013, the country’s GDP grew by 4.7%, with CPI inflation at 2%. In order regional distribution systems and heavy oil development along the eastern to stimulate growth and private investments, Colombia has throughout part of the Tertiary Foreland basins. From 2002 to 2013, Colombian the last years entered into several free trade agreements, which include the production increased at a CAGR of 5.1% for oil and 6.6% for natural gas. is driven mainly by conventional resources located in reservoirs with large agreement with the United States in May 2012 and the creation of the Pacific Alliance with Mexico, Peru and Chile in June 2013. We believe Colombia offers significant potential for value creation through the application of modern technology and exploration strategies on Oil is currently Colombia’s leading export and source of foreign investment. undercapitalized producing fields. Historically, all oil production in the country was from concessions granted to foreign operators or undertaken by Ecopetrol, in contracts of association with foreign companies. During 1999 and 2000, the country was considered to be at risk of becoming a net oil importer unless significant additional reserves were discovered. As a result, Ecopetrol was restructured, and in 2003, a regulatory agency for the sector, the ANH, was created. Following these initial steps, consistent acreage sales to private investors coupled with better 116 GeoPark 20F Colombia-seismic profile (thousand km 2D equivalent) and maintaining attractive conditions for private investments in the hydrocarbon sector and for designing bidding rounds for exploration blocks. 26.5 26.0 24.0 20.1 16.3 11.9 10.0 Any oil company selected by the ANH to explore a specific block must execute either a TEA or an E&P Contract to develop and exploit the block 18.2 with the ANH. All royalty payments in connection with the production of hydrocarbons are made to the ANH in kind unless the ANH grants a specific waiver to make royalty payments in cash or the specific contract provides for payment in cash. Any oil company working in Colombia must present to the ANH periodic reports on the evolution of their exploration and exploitation activities. 6.8 3.5 1.4 2.4 2.1 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Source: ANH ANLA The ANLA was created pursuant to Decree 3573 of 2011 issued by the Colombian government with the participation of the Administrative Regulation of the oil and gas industry Under Colombian law, the state owns all hydrocarbon reserves discovered Department of Public Functions (Departamento Administrativo de la Función Pública), and is responsible for hydrocarbon environmental licensing in in the Colombian territory and exercises control of the exploitation of such Colombia. Any project in the hydrocarbons sector requiring an environmental reserves primarily through the ANH. license must submit to environmental licensing procedures, which require the presentation of an environmental impact assessment, an environmental The ANH is responsible for managing all exploration lands not subject management plan and a contingency plan. Environmental licenses are to previously existing association contracts with Ecopetrol. The ANH began granted for exploration and production phases separately. offering all undeveloped and unlicensed exploration areas in the country under E&P Contracts and Technical Evaluation Agreements, or TEAs, which resulted in a significant increase in Colombian exploration activity and CREG Laws 142 and 143 of 1994 created the CREG, a special administrative unit competition, according to the ANH. The ANH is also in charge of negotiating of the Ministry of Mines and Energy, responsible for establishing the and executing contracts through “direct negotiation” mechanisms with standards for the exploitation and use of energy, regulating the domestic attention to special conditions in the areas to be explored. utilities of electricity and fuel gas (liquefied petroleum gas and natural gas), establishing price rules for energy and gas and regulating self-generation Regulatory entities The principal authorities that regulate our activities in Colombia are the and cogeneration of energy. The CREG is also responsible for fostering the development of the energy services industry, promoting competition Ministry of Mines and Energy, the ANH, the National Environmental Licensing Authority, or the ANLA, and the Regulatory Commission of Energy and Gas, and responding to consumer and industry needs. Decree 4130 of 2011 assigned the CREG new functions that were previously fulfilled by the Ministry or the CREG. of Mines and Energy, including the regulation of tariffs for oil transportation in poliducts and the regulation of petroleum-derived liquid fluids. Ministry of Mines and Energy The Ministry of Mines and Energy is responsible for managing and regulating Colombia’s nonrenewable natural resources, assuring their optimal Superintendency of Domiciliary Public Services Under Colombian regulations, the distribution and marketing of natural utilization by defining and adopting national policies regarding exploration, gas is considered a public service. As such, this activity, as well as electricity, production, transportation, refining, distribution and export of minerals and are regulated by Law 142 of 1994 and supervised by the Superintendency hydrocarbons. of Domiciliary Public Services (Superintendencia de Servicios Públicos Domiciliarios). ANH The ANH was created in 2003 and is responsible for the administration of Colombia’s hydrocarbon reserves. The ANH’s objective is to manage the hydrocarbon reserves owned by the state through the design, promotion Regulatory framework Regulation of exploration and production activities Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon and negotiation of the exploration and production agreements in areas resources located in Colombia and has full authority to determine the rights, where hydrocarbons may be found. The ANH is also responsible for creating royalties or compensation to be paid by private investors for the exploration or GeoPark 20F 117 production of any hydrocarbon reserves. The Ministry of Mines and Energy is programs. A preemptive right is granted to convert the TEA into an E&P the authority responsible for regulating all activities related to the exploration Contract. Exploration activities can only be carried out by the TEA contractor. and production of hydrocarbons in Colombia. Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, their production to the ANH as royalties and an economic right as ANH’s establishes the general procedures and requirements that must be completed participating interest in the production. In 1999, a modification to the royalty by a private investor prior to commencing hydrocarbon exploration or system established a sliding scale for royalty payments, linking them to the production activities. The Petroleum Code sets forth general guidelines, production level of crude oil and natural gas fields discovered after July 29, obligations and disclosure procedures that need to be followed during the 1999 and to the quality of the crude oil produced. Since 2002 the royalties Pursuant to Colombian law, companies are obligated to pay a percentage of performance of these activities. 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 Exploration and production activities were governed by Decree 1895 of 1973 apply to new discoveries and do not alter fields already in their production until September 2009. Decree Law 2310 of 1974 (as complemented by Decree stage. Producing fields pay royalties in accordance with the applicable royalty 743 of 1975) governed the contracts and contracting processes carried out program at the time of the discovery. The purchase price is calculated by Ecopetrol and the rules applicable to such contracts, and also provided based on a reference price for crude oil at the wellhead and varies depending that Ecopetrol was responsible for administering the hydrocarbons resources on prevailing international prices. Decree 2100 of 2011 modified the in the Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of commercialization scheme of natural gas royalties. From 2012 and until 2003, but all agreements entered into by us prior to 2003 with other oil May 2013, producers had to directly commercialize the royalties of their own companies are still regulated by Decree 2310 of 1974. production on behalf of the ANH. In return, the ANH paid a commercialization fee to producers. As of May 2013, contractors must pay in kind royalties Decree Law 1760 of 2003 provided the faculties, structure and functions to third parties called “Royalty Trading Companies” or “Royalty Marketing of the ANH, and granted the ANH full and exclusive authority to regulate Companies,” which are in charge of commercializing the royalties. and oversee the exploration and production of hydrocarbon reserves. Decree Law 1760 of 2003 was complemented by Decree 2288 of 2004, which regulates all aspects related to the reversion of reserves and infrastructure Regulation of refining and petrochemical activities Refining and petrochemical activities are considered to be public utility under the joint venture agreements executed by us before 2004. activities and are subject to governmental regulation. Article 58 of the The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 throughout Colombia. Oil refineries must comply with the technical and Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced characteristics and requirements established by the existing regulations. Petroleum Code establishes that oil refining activities can be developed by Accord 004 of 2012, issued by the Directive Council of the ANH, sets forth the necessary steps for entering into E&P Contracts with the ANH. The Ministry of Mines and Energy is responsible for regulating, supervising This Agreement only regulates the contracts entered into as of May 4, 2012. Prior contracts are still ruled by Agreement 008 of 2004. and overseeing all activities related to the refining of crude oil, import of refined products, storage, transport and distribution. Resolution 18-1495 of 2009 establishes a series of regulations regarding Decree 2657 of 1964 regulated the oil refining activities and created the hydrocarbon exploration and exploitation. In the E&P Contracts, operators Oil Refining Planning Committee, which is responsible for studying industry are afforded access to non-contracted blocks by committing to an exploration problems and implementing short- and long-term refining planning policies. work program. These E&P Contracts provide companies with 100% of new The Committee is also responsible for evaluating and reviewing new production, less the participation of the ANH, which participation may differ refining projects or expansion of existing infrastructure. In evaluating a new for each E&P Contract and depends on the percentage that each company project, the Committee must take into account the significance of the has offered to the ANH in order to be granted with a block, subject to project and the economic impact, the sources of financing, profitability, social an initial royalty payment of 8% and the payment of income taxes of 33%. contribution, the effects on Colombia’s balance of payments and the price In addition, the Colombian government also introduced TEAs, in which structure of the refined products. companies that enter into TEAs are the only ones to have the right to explore, evaluate and select desirable exploration areas and to propose work Pursuant to Resolution 18-0966 of 2006 issued by the Ministry of Mines and commitments on those areas, and have a preemptive right to enter into Energy and Article 58 of the Petroleum Code, any refining company operating an E&P Contract, thereby providing companies with low-cost access to larger in Colombia must provide a portion or, if needed, the total of its production areas for preliminary evaluation prior to committing to broader exploration to supply local demand prior to exporting any production. If the regulated 118 GeoPark 20F production income, the principal item in the price formula, becomes lower maintenance of pipelines must comply with environmental, social, technical than the export parity price, the price paid for the refined products will and economic requirements under national and international standards. be equivalent to the price for those products in the U.S. Gulf Coast market. Transportation networks must follow specific conditions regarding design If there is local demand for imported crudes, the refining company may and specifications, while complying with the quality standards demanded charge additional transportation costs in proportion to the crudes delivered by the oil and gas industry. to the refinery. In 2008, Law 1205 was issued, with the main purpose of contributing to third-party use and owners must offer their capacity on the basis of equal a healthier environment, and established the minimum quality that fuels access to all. Hydrocarbon transport activity may be developed by third should have in the country and the time frame for such a purpose. parties and must meet all requirements established by law. According to Law 681 of 2001, multipurpose pipelines must be open to The Ministry of Mines and Energy establishes the safety standards for LPG, The Ministry of Mines and Energy is responsible for studying and approving storage equipment, maintenance and distribution. Regulations issued the design and blueprints of all pipelines, mediation of rates between parties in 1992 established that every local, commercial and industrial facility with a or, in case of disagreement, establishing the hydrocarbon transport rates storage capacity of LPG greater than 420 pounds must receive authorization based on information furnished by the service provider, issuing hydrocarbon for operations from the Ministry of Mines and Energy. transport regulations, liquidation, distribution and verification of payment of transport-related taxes and managing the information system for the oil As of May 2012, under the powers granted by Decree 4130 of 2011 for product distribution chain. currency and tax matters as well as for royalties, the ANH will determine the crude oil price reference. Regulation of transportation activities Hydrocarbon transportation activity is considered a public utility activity in The construction of transportation systems requires government licenses and local permits awarded by the Ministry of Environment, in addition to other requirements from the regional environmental authorities. Colombia and therefore is under governmental supervision and control. Further regulations on pipeline access and tariff systems have been defined It is also a public service, and pipelines are considered to be public transport by the Ministry of Mines and Energy. Over the past months, the Ministry companies. Transportation and distribution of crude oil, natural gas and of Mines and Energy has been working on a project to modify the 2010 refined products must comply with the Petroleum Code, the Commerce Code regulation of pipeline access and tariff systems. (Código de Comercio) and with all governmental decrees and resolutions. Notwithstanding the general rules for hydrocarbon transportation in Taxation The Tax Statute and Law 9 of 1991 provide the primary features of the oil Colombia, natural gas transportation has specific regulations, due to the and gas industry’s tax and exchange system in Colombia. Generally, national categorization of natural gas distribution as a public utility activity under Colombian laws. Therefore, natural gas distribution transportation is taxes under the general tax statute apply to all taxpayers, regardless of industry. The main taxes currently in effect-after the December 2012 tax governed by specific regulation, issued by the CREG that seeks primarily reform discussed below-are the income tax (25%), the special income tax for to satisfy the needs of the population. the development of social investments (9% for 2013 to 2015 and 8% for The exportation of natural gas is not considered a public utility activity under and the tax on financial transaction (0.4%). Additional regional taxes also Colombian law and therefore is not subject to Law 142 of 1994. Nevertheless, apply. Colombia has entered into a number of international tax treaties the internal supply of natural gas is a priority for the Colombian government. to avoid double taxation and prevent tax evasion in matters of income tax 2016 and beyond) the equity or net assets tax, sales or value added tax (16%), This policy is included in Decree 2100 of 2011, providing that in the event and net asset tax. the supply of natural gas is reduced or halted as a result of a shortage of this hydrocarbon, the Colombian government has the right to suspend the Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international supply of natural gas to foreign customers. Notwithstanding the foregoing, investment regime, regulates foreign capital investment in Colombia. the Decree 2100 of 2011, establishes freedom to export natural gas, under Resolution 8 of the board of the Colombian Central Bank, or the Exchange normal conditions for gas reserves. Statute, and its amendments contain provisions governing exchange operations. Articles 48 to 52 of Resolution 8 provide for a special exchange Transport systems, classified as crude oil pipelines and multipurpose regime for the oil industry that removes the obligation of repayment to the pipelines, can be owned by private parties. The building, operation and foreign exchange market currency from foreign currency sales made by GeoPark 20F 119 foreign oil companies. Such companies may not acquire foreign currency during this 11-year period-3.2% as compared to 1.3%-in great part favored in the exchange market under any circumstances and must reinstate in the by recent discoveries in the pre-salt and offshore Atlantic concessions. foreign exchange market the capital required in order to meet expenses In 2013, oil production reached 2,114 mmbpd. in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by informing the Colombian Similar dynamics took place for the natural gas market, with reserves in 2013 Central Bank, in which case they will be subject to the general exchange jumping to 0.5 trillion cubic meters, or tm3, with an implied 11-year CAGR regime of Resolution 8 and may not be able to access the special exchange of 5.9%, significantly above the global CAGR of 1.7%. Production has also regime for a period of 10 years. grown above the global rate during this period-7.9% as compared to 2.7%- also favored by both non-associated gas finds and gas associated with the On December 26, 2012, Colombian Congress approved a number of tax pre-salt areas. In 2013, natural gas production reached 21.3 bcm. reforms. These changes include, among other things, VAT rate consolidation, a reduction in corporate income tax (from 33% to 25%), changes to Today, offshore fields are the main contributor to reserves and production; transfer pricing rules, the creation of a new corporate income tax to pay for however, the first phase of the production history in the sector, with health, education and family care issues (9% for fiscal years 2013 to 2015 upstream activities dating back to the 1940s, was in the onshore space, with and 8% from 2016 and beyond), modifications in individual income tax, new the Recôncavo Basin in northeast Brazil playing a pivotal role. In 2013, proven “thin capitalization” rules and a reduction of social contributions paid by domestic oil production contributed to more than 91% of total production certain employees. The implementation of such tax reforms requires further (with the remainder located onshore). More than 94% of Brazil's reserves administrative regulation. As of the date of this annual report, some are located offshore, and 80% of all reserves are found offshore near the state administrative regulations had been published, although we do not expect of Rio de Janeiro. Offshore the state of Espirito Santo held the next largest the final impact of these reforms to be material to our business. accumulation at 9% of country's reserves. In December 2014, Colombian Congress approved a tax reform. This Historically, Brazil’s oil and natural gas industry was controlled by Petrobras. reform has introduced a temporary net wealth tax assessed on net equity In 1995, the Brazilian Federal Constitution was amended to allow privately- on domestic and foreign legal entities, kept the rate of the income tax on or publicly-owned companies to engage in the exploration and exploitation equality (enterprise contribution on equality, “CREE” for its Spanish acronym) of oil and natural gas, subject to conditions set forth in specific legislation at 9%, and applied a CREE surcharge until 2018, among other changes. governing the sector. In 1997, the Brazilian Petroleum Law created the ANP The net wealth tax (NWT) assessed on net equity would apply for tax years to promote a transparent regulatory framework and bidding rounds for new 2015 through 2017 for domestic and foreign entities that hold any wealth in concession areas and to regulate and oversee the Brazilian oil and natural Colombia, directly or indirectly, via permanent establishments (PEs) or gas sector. branches. In the case of foreign or domestic individuals, the NWT would apply until 2018. NWT will apply, for corporate taxpayers ,at progressive rates On May 14, 2013, the ANP hosted the 11th oil and gas bidding round offering ranging from 1.15% in 2014; 1% in 2015 and decrease to 0.4% in 2016 and finally disappear in 2017,. NWT paid would not be deductible or creditable 289 concessions, located in 11 basins. These concessions cover approximately 155.8 sq. km. The auction was characterized by a high level of participation for Colombian income tax purposes. The Reform also extended the current and raised R$2.8 billion in proceeds through license fees. Of the 289 9% CREE tax rate, which was scheduled to decrease to 8% in 2016. Also, concessions offered, 142 were successfully bid upon by industry players. it will introduce a new CREE surcharge, beginning in 2015, from 5% in 2015, 6% in 2016, 8% in 2017 and 9% in 2018. Therefore, the accumulated Additionally, on November 28, 2013, the ANP hosted the 12th oil and gas corporate income tax rate will rise to 43% in 2018. bidding round offering 240 concessions, located in seven onshore basins. Brazil Oil and gas industry Recent discoveries in the E&P space have transformed Brazil’s oil and gas industry landscape and turned the country into one of the fastest-growing oil and gas markets in the world. According to the BP Statistical Review, the country’s proved oil reserves in 2013 jumping to 15.6 bboe, an increase of The auction raised R$165.2 million in proceeds through signing bonuses. The round was focused on conventional and unconventional resources with natural gas potential. Of the 240 concessions offered, 72 were successfully bid upon by industry players. Natural gas market in Brazil The natural gas industry in Brazil has undergone significant changes over 1.8% as compared to the previous year. The reserves’ CAGR throughout the the past decade. During this period, natural gas was the fastest-growing last 11 years has reached 4.3%, significantly above the world’s average CAGR component of the non-renewable energy mix in the country. Taking into of 2.2%. Furthermore, production has also grown above the global rate account the increased local production and imports from Bolivia, natural gas 120 GeoPark 20F currently accounts for about 8% of total Brazilian energy demand, according 2,000 km. Local oil pipeline systems connect the fields in the Sergipe-Alagoas, to the 2012 National Energy Balance published by the Energy Research Potiguar and Recôncavo Basins to the coastal export terminals where oil Company, or EPE. Furthermore, according to EPE’s 2021 Ten Year Energy is sent by ship to the refineries in Fortaleza, Bahia and other States. The Expansion Plan, the share of natural gas in overall energy consumption in Brazilian government is expected to announce a ten-year plan for pipeline Brazil should reach 7.8% in 2016 and 8.1% in 2021. Production will be development, or Pemat, similar to what is done today in the power and further boosted with the next bid round, which has been pre-announced by utilities sector, through EPE’s 2021 Ten Year Energy Expansion Plan. the ANP for the fourth quarter of 2013, and which will be dedicated to areas with gas potential according to studies led by the ANP. With a well-established onshore oil and gas industry, the country has an experienced and skilled workforce. Brazil has the capacity for both sustained and rapid growth in natural gas over the next decade, which may potentially change the balance between Oil infrastructure. The oil infrastructure in Brazil is relatively limited, and the natural gas supply and demand in the country. The increased supply majority of oil production is offshore. Oil is loaded onto tankers and shipped could open up new opportunities in the country. Natural gas may not only directly to coastal terminals and refineries or exported. help sustain the continued growth of the local market, but Brazil may also choose to reduce the amount of gas imported and, in the long-term, Gas infrastructure. The gas pipeline network in Brazil is still relatively become a seasonal exporter. underdeveloped despite the significant expansion currently underway. There are many gas transmission pipelines, including international pipelines The increase of the gas supply associated with a growing reserve profile is and a large distribution system. However, the existing infrastructure expected to enable the continued development of the domestic market covers only a small portion of Brazil, primarily serving the main population at rates above the historical ones. Market growth has been largely directed centers of São Paulo and Rio de Janeiro, some states in the south and by increased demand from the industrial and power generation sectors, coastal states in the northeast. which increased their demand for gas by 89.1% between 2002 and 2011, according to the EPE. Brazil’s production profile 2700 2200 1700 1200 500 700 200 -300 2216 192 2373 235 2463 270 2459 310 2458 344 2024 2137 2193 2149 2114 2009 2010 2011 2012 2013 Oil production (mbpd) Gas production (mboepd) Source: BP Statistical Review Brazil’s sedimentary basins The offshore area covers approximately 383.0 million gross acres and the onshore area covers approximately 1,112.0 million gross acres. LNG Brazil began importing LNG in early 2009 through two import terminals, one located in northeast Brazil, in the State of Ceará, and another near the major gas markets in southeast Brazil, in the State of Rio de Janeiro. Both terminals offer re-gasification vessels with an anchor point, which may be connected directly to the national gas network. The terminals are designed to provide flexibility in gas supply and meet the region’s thermoelectric demand. Refineries There are currently 16 refineries operating in Brazil, of which 13 are Petrobras-operated. The current refining capacity is approximately 2.2 mmboepd, up from the 1.9 mmboepd during the 2000s. This increase has been achieved through capacity expansion of the existing refineries. Petrobras has plans to continue the expansion of the country’s refining capacity, and several major projects are either underway or planned that will add a further 1.7 mmboepd of capacity. Regulation of the oil and gas industry Article 177 of the Brazilian Federal Constitution of 1988 provides for the Federal Government’s monopoly over the prospecting and exploration of oil, Infrastructure and workforce Overview. Extensive infrastructure is already in place in the mature coastal natural gas resources and other fluid hydrocarbon deposits, as well as over the refining, importation, exportation and sea or pipeline transportation of basins. The Brazilian midstream infrastructure has grown significantly during crude oil and natural gas. Initially, paragraph one of article 177 barred the recent years. However, it is still small in comparison to other countries, such assignment or concession of any kind of involvement in the exploration of oil as the U.S., China and France. In total, there are 32 oil pipes extending across or natural gas deposits to private industry. On November 9, 1995, however, GeoPark 20F 121 Constitutional Amendment Number 9 altered paragraph one of article 177 policies. Under these regulations, the Brazilian government: (1) introduced a so as to allow private or state-owned companies to engage in the exploration new methodology for determining the price of oil products designed to track and production of oil and natural gas, subject to the conditions to be set prevailing international prices denominated in U.S. dollars, and (2) gradually forth by legislation. eliminated controls on wholesale prices. The Brazilian Petroleum Law, which enacted this constitutional provision: • confirmed the Federal Government’s monopoly over oil and natural gas Concessions 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, hydrocarbons would be regulated and overseen by the federal government; including the ANP, to regulate and control activities in the sector. As part of • created the CNPE (as defined below) and the ANP; • revoked Law Number 2,004/53, which appointed Petrobras as the exclusive agent to execute the Federal Government’s monopoly; and this mandate, the ANP is responsible for licensing concession rights for the exploration, development and production of oil and natural gas in Brazil’s sedimentary basins through a transparent and competitive bidding process. • established a transitional rule that entitled Petrobras to: (1) produce in fields The ANP has conducted 12 bidding rounds for exploration concessions where Petrobras had already started production under a concession since 1999. In November 2013, the twelfth round was conducted; 240 blocks agreement made with the ANP for 27 years, on an exclusive basis, starting in 13 sectors of seven basins were offered, of which 72 were awarded. on the date the field was declared commercially profitable; and (2) explore Of these 72 blocks, we were awarded two new concessions (the PN-T-597 areas where Petrobras was able to show evidence of “established reserves” Concession in the Parnaíba Basin in the State of Maranhão and the prior to the enactment of the Brazilian Petroleum Law, for up to three years, SEAL-T-268 Concession in the Sergipe Alagoas Basin in the State of Alagoas). subsequently extended to five years. Regulatory entities National petroleum, natural gas and biofuel agency (ANP) The Brazilian Petroleum Law created the ANP. The ANP is a regulatory body Our PN-T-597 is still subject to the entry into the concession 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. of the federal government associated with the Ministry of Mines and Energy. In order to participate in the auction process a company must have proven The ANP’s function is to regulate the oil, natural gas and biofuels industry in experience in oil and gas exploration and production activities, be legally Brazil. One of the ANP’s primary objectives is to create a competitive constituted under the laws of their home country and undertake that, environment for oil and natural gas activities in Brazil that will lead to the in the event that they are successful in bidding, the company will constitute lowest prices and best services for consumers. Its principal responsibilities a company with its headquarters and management in Brazil, organized include enforcing regulations as well as awarding concessions related under Brazilian law, and have the determined (specific for each bidding to oil, natural gas and biofuels, in accordance with the Brazilian Petroleum round) minimum net equity. If all requirements are met, the company will be Law, as set forth in Decree No. 2,455, dated January 14, 1998, and regulations considered qualified to bid and make offers for the bidding areas within enacted by the National Council on Energy Policy and National Interest. its category. National council on energy policy (CNPE) The CNPE, also created by the Brazilian Petroleum Law, is a council of the Environmental issues The identification and definition of the concessions to be offered is based President of Brazil presided over by the Minister of Mines and Energy. The on the availability of geological and geophysical data indicating the presence CNPE is charged with submitting national energy policies, designing oil and of hydrocarbons. Also, in order to protect the environment, the ANP, natural gas production policies and establishing the procedural guidelines the IBAMA and the state environmental agencies analyze all the areas prior to for competitive bids regarding the exploration concessions and areas deciding which concessions to offer in licensing rounds. The requirement with established viability in accordance with the Brazilian Petroleum Law. levels for environmental licensing for the various concessions to be auctioned Regulatory framework Pricing policy Until the enactment of the Brazilian Petroleum Law, the Brazilian government regulated all aspects of the pricing of oil and oil products in Brazil, from the cost of oil imported for use in refineries to the price of refined oil products are then published, allowing the future concessionaire to include environmental considerations in determining what projects to pursue. These environmental guidelines are revised and updated with every ANP bidding round. Consortium The oil and natural gas industry is characterized in Brazil by the presence of charged to the consumer. Under the rules adopted following the Brazilian several companies acting through consortium agreements, or unincorporated Petroleum Law, the Brazilian government changed its price regulation joint ventures, in order to share the risks of exploration, development and 122 GeoPark 20F production activities. Terms of those agreements are set out by the ANP and respect to production. Royalties generally correspond to a percentage the actual risk sharing agreement is reflected in joint operating agreements. ranging between 5% and 10% applied to reference prices for oil or natural Taxation Introduction. The Brazilian Petroleum Law introduced significant modifications and benefits to the taxation of oil and natural gas activities. The main component of petroleum taxation is the government take, gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a particular concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. comprised of license fees, fees payable in connection with the occupation or title of areas, royalties and a special participation fee. The introduction of Relevant Tax Aspects on Upstream Activities. The special customs regime for goods to be used in the oil and gas activities in Brazil, REPETRO, aims the Brazilian Petroleum Law presents certain tax benefits primarily with primarily at reducing the tax burden on companies involved in exploring respect to indirect taxes. Such indirect taxes are very complex and can add and extracting oil and natural gas, through the total suspension of federal significantly to project costs. Direct taxes are mainly corporate income tax taxes due on the importation of equipment (platforms, subsea equipment, and social contribution on net profit. among others), under leasing agreements, subject to the compliance with applicable legal requirements. The period in which the goods are Government take. With the effectiveness of the Brazilian Petroleum Law and the regulations promulgated by the ANP, concessionaires are required to allowed to remain in Brazil under the REPETRO regime may vary depending on the importer, but usually corresponds to the duration of the contract pay the Brazilian federal government the following: • license fees; • rent for the occupation or retention of areas; • special participation fee; and • royalties on production. executed between the Brazilian company and the foreign entity, or the period for which the company was 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 The minimum value of the license fees is established in the bidding rules for regulation allows each State to grant the ICMS tax calculation basis reduction the concessions, and the amount is based on the assessment of the potential, (generating a tax burden of 7.5% with the recoverability of credits or 3%, as conducted by the ANP. The license fees must be paid upon the execution without the recoverability of credits) for goods purchased under the of the concession contract. Additionally, concessionaires are required to REPETRO regime for the production phase and the total exemption or ICMS pay a rental fee to landowners varying from 0.5% to 1.0% of the respective tax calculation basis reduction (generating a tax burden of 1.5%, without hydrocarbon production. the recoverability of 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 profitability from oil fields, according to criteria established by applicable regulation, and is payable on a quarterly basis for each field from the date Rio de Janeiro grants tax calculation basis reduction for the exploitation (generating a tax burden of 7.5%, with the recoverability of credits or 3%, on which extraordinary production occurs. This participation rate, whenever without the recoverability of credits) and production of oil and gas due, may reach up to 40% of net revenues depending on (i) volume of (generating a tax burden of 1.5%, without the recoverability of credits). production and (ii) whether the block is onshore, shallow water or deep For production activities, the legislation used to grant an exemption water. Under the Brazilian Petroleum Law and applicable regulations issued of ICMS, which was changed to a tax calculation basis reduction, according by the ANP, the special participation fee is calculated based upon quarterly to Resolution Sefaz No. 631, dated May 14th, 2013. net revenues of each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices It is important to mention that before the enactment of the Convention and the exchange rate for the period) less: No. 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on • royalties paid; • investment in exploration; • operational costs; and 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 • depreciation adjustments and applicable taxes. an 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 The ANP is responsible for determining monthly minimum prices for law is currently being challenged by the Public Ministry in the Supreme petroleum produced in concessions for purposes of royalties payable with Court (ADI 3,019-RJ). GeoPark 20F 123 Pursuant to the Brazilian Petroleum Law and subsequent legislation, the Peru’s production profile federal government enacted Law No. 10,336/01, to impose the Contribution for Intervention in the Economic Sector, or CIDE, an excise tax payable by producers, blenders and importers on transactions with some of oil and fuel products, which is imposed at a flat amount based on the specific quantities of 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 upstream operations, as from 2015 fiscal year, the new tax law may generate timing effects for income tax purposes on the deduction of pre-operational costs as well as depreciation of fixed assets and amortization of intangibles. The new law imposes restrictions for the tax deduction of goodwill arising from in-house operations, and brings several changes to the Brazilian CFC rules. Peru Peru is the eighth largest crude oil reserve holder in Central and South America, with 633 million barrels of proved reserves, as of January 2014, 350 300 250 200 150 100 50 - 230 117 113 163 56 107 292 298 182 110 191 107 300 197 104 2009 2010 2011 2012 2013 Oil production (mbpd) Gas production (mboepd) Peruvian hydrocarbon legislation. The hydrocarbons activities in Peru are mainly regulated by the General Hydrocarbons Law (Law 26,221), and several regulations enacted in order to develop the provisions included in such law. according to Oil and Gas Journal. Much of Peru’s proved oil reserves are According to the Hydrocarbons Law, oil and gas exploration and production located onshore in the Amazon region. Proved natural gas reserves in activities are carried out under license or service contracts granted by the Peru were 15.4 trillion cubic feet in 2014, the third largest in Central and government. Under a license contract, the investor pays a royalty, whereas South America following Venezuela and Mexico. under a service contract, the government pays remuneration to the contractor. As stated by the Peruvian Constitution and the Organic Law for Crude oil production in Peru has been declining since the mid-1990s, but Hydrocarbons, a license contract does not imply a transfer or lease of the country’s total liquid fuels production has been bolstered by increased property over the area of exploration or exploitation. By virtue of the license output of natural gas liquids (“NGLs”). As a result, total liquid fuels production contract, the contractor acquires the authorization to explore or to exploit has steadily increased over the past decade to average 175,000 barrels per hydrocarbons in a determined area, and Perupetro (the entity that day (b/d) in 2013, of which nearly 60% was NGLs. holds the Peruvian state interest) transfers the property right in the extracted hydrocarbons to the contractor, who must pay a royalty to the state. Petroleum consumption in Peru averaged 171,000 b/d in 2013. Peru imports crude oil and refined products to satisfy both domestic demand and export commitments. The country imports most of its crude oil from Ecuador, License and service contracts are approved by a supreme decree issued by the Peruvian Ministry of Economy and Finance, and the Peruvian Ministry with smaller amounts from other countries in South America and West Africa. of Energy and Mining, and can only be modified by a written agreement signed by the parties. Before initiating any negotiation, every oil and gas Peru has six oil refineries with a total crude distillation capacity of almost company must be duly qualified by Perupetro, in order to determine if 199,000 b/d. Repsol YPF operates the largest refinery in the country, it fulfills all the requirements needed to develop exploration and production the 108,000-b/d La Pampilla refinery located in Lima. Most of the other activities under the contract form requirements mentioned above. When refineries are owned by the state-owned company, Petroperú. a contractor is a foreign investor, it is expected to incorporate a subsidiary company or registered branch in accordance with Peru’s laws and to appoint Dry natural gas production in Peru has grown rapidly since the Camisea field local representatives who will interact with Perupetro. went on stream in 2004. Peru became a natural gas exporter in 2010 when it commissioned South stage -when a commercial discovery has been made- or for an exploration America’s first liquefied natural gas (“LNG”) plant, Melchorita. and exploitation stage -when such discovery has not been made yet. In this License and services agreements may be granted for just an exploitation case, the exploration phase will last no more than 7 years, counted from the effective date of the contract (60 days after the signing date). This term can be divided into several periods as agreed in the contract, and all of them 124 GeoPark 20F with a minimum work obligation that should be fulfilled by a contractor in camps, means of communication, equipment and other goods that the order to access to the next exploration period. The exploitation phase contractor keeps or recovers to use in the same operations or in other will last 40 years from the effective date of the contract in case of natural gas operations of a different nature. discoveries and 30 years from the effective date in case of oil discoveries. The Ministry of Energy and Mines may exceptionally authorize an extension separately and for each contract. If the contractor carries out related activities of three years for the exploration stage, if the contractor has fulfilled with the (i.e., activities related to oil and gas, but not carried out under the terms minimum work program established in the contract, and also commits to of the contract) or other activities (i.e., activities not related to oil and gas), fulfill an additional work program that justifies such extension. The contractor the contractor is obligated to determine the tax base and the amount shall be responsible for providing the technical and economic resources of tax, separately, and for each activity. The contractor determines the tax base and the amount of the tax, required for the execution of the operations of this phase. The Peruvian regulations also established the roles of the Peruvian that apply in each case (subject to the tax stability provisions for contract government agencies that regulate, promote and supervise oil and gas activities and based on the regular regime for the related activities or industry, including the Ministry of Energy and Mines, Perupetro and other activities). The total income tax amount that the contractor must pay is The corresponding tax is determined based on the income tax provisions OSINERGMIN. the sum of the amounts calculated for each contract, for both the related activities and for the other activities. The forms to be used for tax statements Peruvian tax regime. The fiscal regime that applies in Peru to the oil and gas industry consists of and payments are determined by the tax administration. If the contractor has more than one contract, it may offset the tax losses generated by one a combination of corporate income tax, royalties and other levies. or more contracts against the profits resulting from other contracts or related activities. Moreover, the tax losses resulting from related activities may be In general terms, oil and gas companies are subject to the general corporate offset against the profits from one or more contracts. income tax regime; nevertheless, there are certain special tax provisions for the oil and gas sector. Resident companies (incorporated in Peru), It is possible to choose the allocation of tax losses to one or more of the are subject to income tax on their worldwide taxable income. Branches and contracts or related activities that have generated the profits, provided that the permanent establishments of foreign companies that are located in Peru losses are depleted or are compensated to the limit of the profits available. and non-resident entities are taxed on income from Peruvian sources only. This means that if there is another contract or related activity, the taxpayer can continue compensating tax losses until they are totally used. A contractor Taxable income is generally computed by reducing gross revenue by cost of with tax losses from one or more contracts or related activities may not offset goods sold and all expenses necessary to produce the income or maintain them against profits generated by the other activities. Furthermore, in no case the source of income. Certain types of revenue, however, must be computed may tax losses generated by the other activities be offset against the profits as specified in the tax law and some expenses are not fully deductible for tax purposes. Business transactions must be recorded in legally authorized resulting from the contracts or from the related activities. accounting records that are in full compliance with the International During the exploration phase, operators are exempt from import duties Accounting Standards (IAS). Contractors in a license or services contract and other forms of taxation applicable to goods intended for exploration for the exploration or exploitation of hydrocarbons (Peruvian corporations activities. Exemptions are withdrawn at the production phase, but exceptions and branches) are entitled to keep their accounting records in foreign are made in certain instances, and the operator may be entitled to currency, but taxes must be paid in Peruvian Nuevos Soles (“PEN”). temporarily import goods tax-free for a two-year period (“Temporary Import”). Any investments in a contract area that did not reach the commercial up to two years upon the request of an operator, approval of the Ministry of extraction stage and that were totally released, can be accumulated with the Energy and Mines and authorization of the Superintendencia Nacional same type of investments made in another contract that is in the process of de Aduanas y de Administración Tributaria (Peruvian Customs Agency). A temporary Import may be extended for additional one year periods for commercial extraction. These investments are amortized in accordance with the amortization method chosen in the letter contract. If the contractor has entered into a single contract, the accumulated investments are charged Peruvian labor and safety legislation. Indefinite-term contracts are the general rule for hiring in Peru, although as a loss against the results of the contract for the year of total release of the fixed-term contracts and part-time contracts may also be signed as an area for any contract that did not reach the commercial extraction stage, exception. In any labor contract in Peru, the workers will usually have, among with the exception of investments consisting of buildings, power installations, others, the following labor benefits: a) vacation time, b) two legal bonuses GeoPark 20F 125 (each one equal to one month of salary), c) severance payment (CTS), d) The competent authority for approving the environmental studies is the family allowance, e) public health insurance, and f) life insurance. Ministry of Energy and Mines, through the General Bureau of Energetic In addition, companies that generate business income are required to Ministry of Environment in the short term. distribute a percentage of their annual income among their workers. The percentage to be distributed depends on the activity to be performed There are general environmental regulations for the protection of water, by the company. In case of companies that perform oil and gas activities, soils, air, endangered species, biodiversity, natural protected areas, etc. the percentage will be 5%. In addition, there are specific environmental regulations applicable to the Environmental Affairs (GBEEA). However, such role will be assumed by the Employment contracts can only be terminated based on the reasons provided by Peruvian law. If an employment contract is terminated for any Argentina hydrocarbon industry. other reason, the employer will be required to pay damages to the employee for arbitrary dismissal (calculated according to the length of service), or may Oil and gas industry Argentina is the second-largest producer of natural gas and the fourth-largest be required to reinstate the employee. producer of crude oil in Central and South America, according to the BP Foreign workers are allowed by Peruvian labor laws. However, such workers gas in South America, and has a globally significant unconventional oil and should not exceed the 20% of the total workforce of the company, except gas resource base. Production of both oil and natural gas throughout the last by specialized technical staff or management staff for new business activities. years has been dropping as a result of the maturing of the production fields Any foreign worker will need a proper immigration visa work in Peru. and lack of investment. In 2013, the country’s natural gas production reached Statistical Review. The country is a leading producer and consumer of natural 35.5 bcm, with oil production at 656 mmbblpd. There are several regulations for protecting the safety and health of the workers. Oil and gas companies are obliged to fulfil not only the general In response to the economic crisis of 2001 and 2002, the Argentine regime included in the labor laws, but also the specific regime approved government, pursuant to the Public Emergency Law (Law No. 25,561), for hydrocarbons activities. These regulations contain provisions on accident established export taxes on certain hydrocarbon products. In subsequent prevention, living conditions, sanitary facilities, water quality in the years, in order to satisfy growing domestic demand and abate inflationary workplaces, medical assistance and first-aid services, safety measures related pressures, this law was supplemented by constraints on domestic prices, to camps, medical assistance, food conditions, handling of explosives, etc. export restrictions and subsidies on imports of natural gas and diesel, among Peruvian environmental regulation. Before initiating any hydrocarbon activity (e.g. seismic exploration, drilling of exploration wells, etc.) the contractor must file and obtain an approval other measures. As a result, local prices for oil and natural gas products had remained significantly below those prevalent in neighboring countries and international commodity exchanges. for an Environmental Impact Study (EIS), which is the most important permit related to HSE for any hydrocarbon project. This study includes technical, After declining during the economic crisis of 2001 and 2002, Argentina’s real gross domestic product, or GDP, grew at a compounded average environmental and social evaluations of the project to be executed in order growth rate, or CAGR, of 8.5% from 2003 to 2008. Although the growth rate to define the activities that should be required for preventing, minimizing, decelerated to 0.9% in 2009 as a result of the global financial crisis, it mitigating and remediation of the possible negative environmental and recovered in 2010 and 2011, growing at an annual rate of approximately 9%, social impacts that the hydrocarbon project may generate. respectively, according to preliminary official data. In 2012, the Argentine Depending on the type of hydrocarbon activity the contractor is intended to an annualized basis compared to the preceding year according to the execute, it should file the following types of environmental studies: methodology of calculation prevailing until March 2014. On March 27, 2014, economy experienced a slowdown with GDP increasing at a rate of 1.9% on • Environmental Impact Statement (EIS). • Environmental Impact Study (EIS). the Argentine government announced a new method of calculating GDP by reference to 2004 as the base year (as opposed to 1993, which was the base reference year under the prior method of calculating GDP). As a result • Semi detailed Environmental Impact Study (SEIS). of the application of this new method, the estimated GDP for 2013 was revised from 4.9% to 2.9%. In Argentina, widespread import and exchange controls also affected business confidence and investment. 126 GeoPark 20F Argentina’s production profile 1400 1200 1000 800 600 400 200 - 1411 1369 1312 1272 1229 668 647 625 607 573 743 722 687 665 656 2009 2010 2011 2012 2013 Oil production (mbpd) Gas production (mboepd) Source: BP Statistical Review Decrees, relating specifically to deregulation of energy activities). The Oil Deregulation Decrees eliminated restrictions on imports and exports of crude oil, deregulated the domestic oil industry, and effective January 1, 1991, the prices of oil and petroleum products were also deregulated. In 1992, Law No. 24,145, referred to as the Privatization Law, privatized YPF and provided for transfer of hydrocarbon reservoirs from the Argentine government to the provinces, subject to the existing rights of the holders of exploration permits and production concessions. In October 2004, the Argentine Congress enacted Law No. 25,943, creating a new state-owned energy company, Energía Argentina S.A., or ENARSA. The corporate purpose of ENARSA is the exploration and exploitation of solid, liquid and gaseous hydrocarbons; the transport, storage, distribution, commercialization and industrialization of these products; as well as the transportation and distribution of natural gas, and the generation, Driven by economic expansion and stable domestic prices, energy transportation, distribution and sale of electricity. Moreover, Law No. 25,943 consumption has increased significantly from 2002 to 2013, with demand granted ENARSA all offshore areas located beyond 12 nautical miles for oil and gas increasing from 331.7 mboe in 2002 to 448 mboe in 2013. from the coastline up to the outer boundary of the continental shelf that were Argentine natural oil and gas consumption grew at a CAGR of approximately vacant at the time of the effectiveness of this law (i.e., November 3, 2004). 4.4% during this period, according to the BP Statistical Review. In recent years, demand has outpaced energy supply (in 2013, the deficit reached On May 3, 2012, the Argentine Congress passed the Hydrocarbons 66 mboe). As a result of this increasing demand and the maturing of local Sovereignty Act. This law declared achieving self-sufficiency in the supply reserves the country’s production surplus has shifted toward a deficit. of hydrocarbons, as well as in the exploitation, industrialization, Still, according to the BP Statistical Review, Argentina’s R/P ratio is at 9.8x transportation and sale of hydrocarbons, a national public interest and for oil and 8.9x for gas. a priority for Argentina. In addition, the law expropriated 51% of the share capital of YPF, the largest Argentine oil company, from Repsol, the Regulation of the oil and gas industry Under Argentine law, the federal executive branch establishes the federal largest Spanish oil company. policy applicable to the exploration, exploitation, refining, transportation and On July 28, 2012, Presidential Decree 1277/2012, which regulated the marketing of liquid hydrocarbons, but the licensing and enforcement of Hydrocarbon Sovereignty Law, was released, establishing that the Strategic exploration and production activities has been transferred from the federal Planning and Coordination Committee for the National Hydrocarbon government to provincial governments. Regulatory entities The principal authorities that regulate the activities in Argentina are the Investment Plan must be in charge of the sector’s reference prices. The decree introduced important changes to the rules governing Argentina’s oil and gas industry. The decree repeals certain articles of Deregulation Decrees passed during 1989 relating to free marketability of hydrocarbons at Secretariat of Energy and the Strategic Planning and Coordination Committee negotiated prices, the deregulation of the oil and gas industry, freedom to for the National Hydrocarbon Investment Plan, at the federal level, and a import and export hydrocarbons and the ability to keep proceeds from local enforcement authority at each province (typically a secretariat of energy export sales in foreign bank accounts. The repeal of these articles appears or hydrocarbons board). to formalize certain rules such as price controls and the repatriation of export sales proceeds, which has been in fact required by the government over Regulatory framework From the 1920s to 1989, the Argentine public sector dominated the upstream the last several years. segment of the Argentine oil and gas industry and the midstream and In addition, the decree created the Strategic Planning and Coordination downstream segment of the business. Committee for the National Hydrocarbon Investment Plan, charged In 1989, Argentina enacted certain laws aimed at privatizing the majority of reserves and to make Argentina more energy self-sufficient. The decree also its state-owned companies and issued a series of presidential decrees requires oil and gas companies, refiners and transporters of hydrocarbon (namely, Decrees No. 1055/89, 1212/89 and 1589/89, or the Oil Deregulation products to submit annual investment plans for approval by the commission. with developing investment plans for the country to increase production and GeoPark 20F 127 The decree empowers the commission to issue fines and sanctions, Until 1989, crude oil production, whether extracted by YPF or by private including concession termination, for companies that do not comply with companies operating under service contracts, was delivered to YPF, and the its requirements. Finally, the Strategic Planning and Coordination Committee Secretariat of Energy distributed the same among the refining companies for the National Hydrocarbon Investment Plan is also charged with the according to quotas. Natural gas production was until then also delivered to responsibility of assuring the reasonableness of hydrocarbon prices in the YPF and to the then existing state-owned Gas del Estado SE utility company. domestic market and that such prices allow companies to generate a reasonable profit margin. Domain and Jurisdiction of hydrocarbons resources After a constitutional reform enacted in 1994, eminent domain over hydrocarbon resources lying in the territory of a provincial state is now vested The Oil Deregulation Decrees issued in 1989 deregulated the hydrocarbons industry and granted to the holders of hydrocarbon permits and concessions the right to freely dispose of the hydrocarbons lifted by them at free market conditions, and abrogated the previous quota allocation system. in such provincial state, while eminent domain over hydrocarbon resources After the economic crisis of 2001 and 2002, hydrocarbons refiners and lying offshore on the continental platform beyond the jurisdiction of the producers were prompted by the Argentine government to enter into a series coastal provincial states is vested in the federal state of tripartite agreements whereby the prices of crude oil and certain byproducts were capped or regulated. A series of other measures was also Thus, oil and gas exploration permits and exploitation concessions are now adopted, affecting the downstream segment of the industry. granted by each provincial government. A majority of the existing concessions were granted by the federal government prior to the enactment of Law No. 26,197 and were thereafter transferred to the provincial states. Regulation of transportation activities Exploitation concessionaires have the exclusive right to obtain a transportation concession for the transport of oil and gas from the provincial Regulation of exploration and production activities states or the federal government, depending on the applicable jurisdiction. New Hydrocarbon Act: In October 31, 2014 the Argentine Republic Official Gazette published the Such transportation concessions include storage, ports, pipelines and other fixed facilities necessary for the transportation of oil, gas and by-products. text of Law No. 27,007, amending the Hydrocarbon Law No. 17,319. Transportation facilities with surplus capacity must transport third parties’ hydrocarbons on an open-access basis, for a fee which is the same for The most relevant aspects of the new law are as follows: • With regards to concessions, three types of concessions are provided, all users on similar terms. As a result of the privatizations of YPF and Gas del Estado, a few common carriers of crude oil and natural gas were chartered namely, conventional exploitation, unconventional exploitation, and and continue to operate to date. exploitation in the continental shelf and territorial waters, establishing the respective terms for each type. • The terms for hydrocarbon transportation concessions were adjusted in order to comply with the exploitation concessions terms. • With regards to royalties, a maximum of 12% is established, which may Taxation Exploitation concessionaires are subject to the general federal and provincial tax regime. The most relevant federal taxes are the income tax (35%), the value added tax (21%) and a tax on assets. The most relevant provincial taxes reach 18% in the case of granted extensions, where the law also establishes are the turnover tax (1% to 3%) and stamp tax. In 2002, in response to the the payment of an extension bond for a maximum amount equal to the economic crisis, the federal government adopted new taxes on oil and gas amount resulting from multiplying the remaining proven reserves at the end products, including export taxes ranging from 5% for by-products to 45% of effective term of the concession by 2% of the average basin price for crude oil. Despite that, under certain incentives programs established applicable to the respective hydrocarbons over the 2 years preceding the in 2008 (namely, the Oil Plus Program and the Refining Plus Program created time on which the extension was granted. by Presidential Decree 2014/2008), oil and gas companies increasing their • The extension of the Investment Promotion Regime for the Exploitation of oil reserves and production and refining companies increasing their Hydrocarbons (Decree No. 929/2013) is established for projects representing production would be granted tax rebate certificates to be credited against a direct investment in foreign currency of at least 250 million dollars, the payment of the export taxes. However, the Oil Plus Program and the increasing the benefits for other type of projects. Refining Plus Program were suspended for certain companies in February 2012 and subsequently amended and reinstated in June 2012. Regulation of refining and petrochemical activities Refining and petrochemical activities in Argentina have historically been governed by free enterprise and private refineries have coexisted with state-owned refineries. 128 GeoPark 20F C. Organizational structure We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. The following chart shows our main corporate structure as of December 31, 2014. 100% GeoPark Latin America Limited – Bermuda (Bermuda) 100% GeoPark Latin America Limited Agencia en Chile (Chile) GeoPark Limited (Bermuda) 100% 1% 99.9% 99.9% 99.9% GeoPark Argentina Limited – Bermuda (Bermuda) GeoPark Latin America Coöperatie U.A. (Netherlands) GeoPark Brazil Coöperatie U.A. (Netherlands) GeoPark Brazil Coöperatie U.A. (Netherlands) 100% 80% GeoPark Argentina Limited - Argentinean Branch (Argentina) GeoPark Colombia Coöperatie U.A. (Netherlands) 20% LG International* 100% GeoPark Colombia SAS (Colombia) 99.9% GeoPark Brazil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) 100% Rio das Contas Produtora de Petróleo Ltda (Brazil) 80% 99.9% 100% LG International* 20% GeoPark Chile S.A. (Chile) GeoPark S.A. (Chile) GeoPark Colombia S.A. (Chile) 99.9% GeoPark SAC (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) Bermuda Companies Chilean Companies Argentinean Companies Colombian Companies Brazilean Companies Netherlands Companies Peruvian Companies (*) LGI is not a subsidiary. It is Non-controlling interest. D. Property, plant and equipment See “-B. Business Overview-Title to properties” Following the completion of our pending Morona Block Acquisition which we expect to take place in 2015, we expect GeoPark Perú will hold the assets we acquire in Peru. GeoPark 20F 129 ITEM 4A. UNRESOLVED STAFF COMMENTS Not applicable. In March 2014 we invested US$140.1 million in Brazil to acquire Rio das Contas, which we financed through the incurrence of a loan of US$70.5 million and cash on hand. ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS At the base budget oil price assumption of US$45-US$50 per bbl, GeoPark A. Operating results is targeting a fully-funded US$60 million-US$70 million work and investment program. The bulk of this 2015 work program is targeted to further develop The following discussion of our financial condition and results of operations and produce GeoPark’s Tigana and Tua oil fields in the Llanos 34 Block in should be read in conjunction with our Consolidated Financial Statements and Colombia, which currently provide the lowest risk production and reserve the notes thereto, included elsewhere in this annual report, as well as the growth opportunities with attractive operating netbacks. information presented under “-Item 3. Key Information- A. Selected financial data.” The work program break-down is approximately as follows: Colombia with US$35 million-US$40 million in new drilling and facility construction; The following discussion contains forward-looking statements that involve risks Chile with US$5 million-US$8 million in well workovers and facility and uncertainties. Our actual results may differ materially from those discussed construction; Brazil with US$6 million-US$7 million in the Manatí compression in the forward-looking statements as a result of various factors, including plant installation and seismic processing; Peru with US$8 million-US$9 those set forth in “-Item 3. Key Information-D. Risk factors” and “Forward-looking million mainly in environmental studies; and Argentina with US$3 million- statements.” US$4 million in seismic studies Factors affecting our results of operations We describe below the year-to-year comparisons of our historical results and If oil prices average higher than the base budget price, GeoPark has the ability to allocate additional capital to more projects and increase its work the analysis of our financial condition. Our future results could differ and investment program and thereby further increase oil and gas production. materially from our historical results due to a variety of factors, including the following: Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves Discovery and exploitation of reserves Our results of operations depend on our level of success in finding, acquiring that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to (including through bidding rounds) or gaining access to oil and natural gas exploration blocks that contain reserves. Unless we succeed in exploration and reserves. While we have geological reports evaluating certain proved, development activities, or acquire properties that contain new reserves, our contingent and prospective resources in our blocks, there is no assurance that anticipated reserves will continually decrease, which would have a material we will continue to be successful in the exploration, appraisal, development adverse effect on our business, results of operations and financial condition. and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, Oil and gas revenue and international prices Our revenues are derived from the sale of our oil and natural gas production, and, even if we are able to successfully make such discoveries, there is no as well as of condensate derived from the production of natural gas. certainty that the discoveries will be commercially viable to produce. We have Our oil and natural gas prices are driven by the international prices of oil been able to successfully develop our assets through drilling, with 72%, or and methanol (for our Chilean gas production), respectively, which are 147, of the 205 exploratory, appraisal and development wells that we drilled denominated in U.S. dollars. The price realized for the oil we produce is from January 1, 2006 through December 31, 2014 becoming productive wells. linked to WTI and Brent, U.S. dollar denominated international benchmarks. The price realized for the natural gas we produce in Chile is linked to the For the year ended December 31, 2014, we drilled 53 new wells, 32 in Chile, international price of methanol, which is settled in the international markets and 21 in Colombia and acquire seismic in Brazil in blocks in which we in U.S. dollars. The market price of these commodities is subject to significant have working interests and/or economic interests. We made total capital fluctuation and has historically fluctuated widely in response to relatively expenditures of US$238.0 million (US$154.3 million, US$71.4 million, US$0.2 minor changes in the global supply and demand for oil and natural gas, million, US$0.7 million and US$11.4 million in Chile, Colombia, Argentina, market uncertainty, economic conditions and a variety of additional factors. Peru and Brazil, respectively) for the year 2014, consisting of US$97.9 million related to exploration. 130 GeoPark 20F For example, from January 1, 2010 to December 31, 2014, Brent spot prices If the market prices of WTI, Brent and methanol had fallen by 10% as ranged from a low of US$55.27 per barrel to a high of US$128.14 per barrel, compared to actual prices during the year, with all other variables held NYMEX WTI crude oil contracts prices ranged from a low of US$53.45 per bbl constant, after-tax profit for the year ended December 31, 2014 would to a high of US$113.39 per bbl, Henry Hub natural gas average spot prices have been lower by US$29.2 million (US$27.2 million in 2013). ranged from a low of US$1.82 per mmbtu to a high of US$8.15 per mmbtu, US Gulf methanol spot barge prices ranged from a low of US$240.34 per metric In Brazil, prices for gas produced in the Manatí Field are based on a ton to a high of US$564.12 per metric ton. We have historically not hedged long-term off-take contract with Petrobras. For the year ended December 31, our production to protect against fluctuations in the international oil prices. 2014, Rio das Contas’s average sale price was US$39/boe. The price of gas As a consequence of the oil price crisis which started in the second half of inflation pursuant to the Brazilian General Market Price Index (Índice Geral sold under this contract is denominated in reais and is adjusted annually for 2014 (WTI and Brent, the main international oil price markers, fell by de Preços-Mercado), or IGPM. approximately 50% between August 2014 and March 2015), the Company has undertaken a decisive cost cutting program to ensure its ability to both We do not have a price-hedging transaction currently outstanding. Our maximize the work program and preserve its cash. For more information Board of Directors could consider adopting commodity price hedging see “-Item 3. Key Information-D. Risk Factors-Risks relating to our business- measures, when deemed appropriate, according to the size of the business, Current oil industry price crisis and the impact on GeoPark’s operations.” production levels and market volatility. Additionally, the oil and gas we sell may be subject to certain discounts. For instance, in Chile, the price of oil we sell to ENAP is based on Brent minus Production costs Our production costs consist primarily of expenses associated with the certain marketing and quality discounts based on, among other things, production of oil and gas, the most significant of which are gas plant leasing, API and mercury content. Mercury content can vary depending on the facilities and wells maintenance (including pulling works), labor costs, geology and features in each field. As a result, our average realized price for contractor and consultant fees, chemical analysis, royalties and products, the years ended December 31, 2014 and 2013 was of US$89.4 per bbl and among others. As commodity prices increase or decrease, our production US$84.3 per bbl, respectively. costs may vary. We have historically not hedged our costs to protect We have a long-term gas supply contract with Methanex. The price of the against fluctuations. gas 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 Our business depends on the availability and reliability of operating and spot barge prices, methanol spot Rotterdam prices and spot prices in Asia. transportation infrastructure in the areas in which we operate. Prices See “-Item 3. Key Information-D. Risk factors-Risks relating to our business- and availability for equipment and infrastructure, and the maintenance A substantial or extended decline in oil, natural gas and methanol prices may thereof, affect our ability to make the investments necessary to operate materially adversely affect our business, financial condition or results of operations.” As of the date of this annual report, we had not entered into any our business, and thus our results of operations and financial condition. See “-Item 3. Key Information-D. Risk factors-Risks relating to our business- derivative arrangements or contracts to mitigate the impact on our results Our inability to access needed equipment and infrastructure in a timely of operations of fluctuations in commodity prices. manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.” In Colombia, the price of oil we sell is based on Brent, adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, In order to mitigate the risk of unavailability of operating and transportation sulfur, delivery point and water content, as well as on certain transportation infrastructure, we have invested in the construction of plant and pipeline costs (including pipeline costs and trucking costs). The delivery points infrastructure to produce, process and store hydrocarbon reserves and to for our production range from the well head to the port of export (Coveñas), transport them to market. In the Fell Block, for example, we have constructed depend on the client: if sales are made via pipeline, the delivery point is over 120 km of pipeline and a gas plant with a processing and compression usually the pipeline injection point, whereas for direct export sales, the most capacity of 35.3 mmcfpd. We also constructed an oil treatment plant with frequent delivery point is the well head. As a result, our average realized a processing capacity of 9,500 bopd to service oil produced in the Fell Block, price for the year ended December 31, 2014 was US$73.0 per bbl. 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 receive or deliver the production, as applicable. GeoPark 20F 131 Production levels Our oil and gas production levels are heavily influenced by our drilling results, administrative costs may continue to increase as a result of our Peruvian operations, and as a result of becoming a publicly traded company in the our acquisitions and, to a lesser extent, oil and natural gas prices. Since being United States. Public company costs include expenses associated with our awarded 100% of the working interest in the Fell Block in 2006, and through annual and quarterly reporting, investor relations, registrar and transfer agent December 31, 2014, we have drilled 113 exploratory, appraisal and fees, incremental insurance costs and accounting and legal services. development wells in the Fell Block, with 76%, or 86, of such wells becoming productive. Production at the Fell Block has increased from 3,292 boepd in 2008 to 5,850 boepd as of December 31, 2014. Since acquiring our Colombian Acquisitions Our results of operations are significantly affected by our past acquisitions. operations and through December 31, 2014, 67 exploratory, appraisal and We generally incorporate our acquired business into our results of operations development wells have been drilled in blocks in which we have working at or around the date of closing, such as our Colombian acquisitions in 2012 interests and/or economic interests, with 69% of such wells becoming and our Rio das Contas acquisition in 2014, which limits the comparability of productive. Production in our Colombian operations has increased from 2,965 the period including such acquisitions with prior or future periods. boepd for the month of April 30, 2012 to 10,807 boepd for the year ended December 31, 2014. As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, We expect that fluctuations in our financial condition and results of producing properties and concessions, as the pending Morona Block. As with operations will be driven by the rate at which production volumes from our our historical acquisitions, any future acquisitions could make year-to-year wells decline. As initial reservoir pressures are depleted, oil and gas comparisons of our results of operations difficult. We may also incur production from a given well will decline over time. See “-Item 3. Key additional debt, issue equity securities or use other funding sources to fund Information-D. Risk factors-Risks relating to our business-Unless we replace future acquisitions. our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill Functional and presentational currency Our Consolidated Financial Statements are presented in U.S. dollars, which is in the future may not yield oil or natural gas in commercial quantities.” our functional and presentational currency. Items included in the financial information of each of our entities are measured using the currency of the Contractual obligations In order to protect our exploration and production rights in our license areas, primary economic environment in which the entity operates, or the functional currency, which is the U.S. dollar in each case, except for our Brazil operations, we must make and declare discoveries within certain time periods specified in where the functional currency is the real. our various special contracts, E&P Contracts and concession agreements. The 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 We divide our business into five geographical segments-Chile, Colombia, agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these Brazil, Peru and Argentina-that correspond to our principal jurisdictions of operation. Activities not falling into these four geographical segments are agreements, or in securing new ones, our ability to grow our business may be reported under a separate corporate segment that primarily includes certain materially impaired. See “-Item 3. Key Information-D. Risk factors-Risks relating corporate administrative costs not attributable to another segment. to our business-Under the terms of some of our various CEOPs, E&P Contracts As of December 31, 2014, our Chilean segment contributed US$145.7 million, and concession agreements, we are obligated to drill wells, declare any or 34.0%, of our revenues, our Colombian segment contributed US$246.1 discoveries and file periodic reports in order to retain our rights and establish million, or 57.4%, of our revenues, our Brazilian segment contributed development areas. Failure to meet these obligations may result in the loss of US$35.6 million, or 8.3%, of our revenues and our Argentine segment our interests in the undeveloped parts of our blocks or concession areas.” contributed US$1.3 million, or 0.3%, of our revenues. Administrative costs Our administrative costs for the year ended December 31, 2014 increased by In the description of our results of operations that follow, our “Other” operations reflect our non-Chilean, non-Colombian and non-Brazilian US$1.6 million, or 3.4%, compared to the year ended December 31, 2013. Our operations, primarily consisting of our Argentine, Peruvian (mainly related to administrative costs increased by US$17.8 million, or 61.8%, from 2012 to the start-up of our operations in such country) and corporate head office 2013, mainly due to (i) higher corporate expenses related to our growth operations. strategy and new business efforts, (2) increased staff costs in Colombia, and (iii) the start-up of our operations in Tierra del Fuego, Chile. Furthermore, 132 GeoPark 20F Description of principal line items The following is a brief description of the principal line items of our statement Selling expenses Selling expenses consist primarily of transportation and storage costs. of income. Net revenue Net revenue includes the sale of crude oil, condensate and natural gas net Financial results, net Financial results, net consists of financial income offset by financial expenses. Financial income includes interest received from bank time deposits and the of value-added tax, or VAT, and discounts related to the sale (such as API and effect of exchange rate differences. Financial expenses principally include mercury adjustments) and overriding royalties due to the ex-owners of oil interest expense not subject to capitalization, bank charges, the effect of and gas properties where the royalty arrangements represent a retained exchange rate differences and the unwinding of long-term liabilities. working interest in the property. Revenue is recognized when the significant risks and rewards of ownership have been transferred to the buyer, the associated costs and amount of revenue can be estimated reliably, recovery Profit for the period attributable to owners of the Company Profit for the period attributable to owners of the Company consists of profit of the consideration is probable, and there is no continuing management for the year less non-controlling interest. involvement with the goods. Production costs For a description of our production costs, see “-Factors affecting our results of operations.” Critical accounting policies and estimates We prepare our Consolidated Financial Statements in accordance with IFRS and the interpretations of the IFRS Interpretations Committee, or the IFRIC, as adopted by the IASB. The preparation of the financial statements requires us to make judgments, estimates and assumptions that affect the reported Capitalized costs of proved oil and natural gas properties are depreciated on amounts of assets, liabilities, revenue and expenses, and related disclosure of a licensed-area-by-licensed-area basis, using the unit of production method, contingent assets and liabilities. We continually evaluate these estimates and based on commercial proved and probable reserves as calculated under assumptions based on the most recently available information, our own the Petroleum Resources Management System methodology promulgated historical experience and various other assumptions that we believe to be by the Society of Petroleum Engineers and the World Petroleum Council, reasonable under the circumstances. Since the use of estimates is an integral or the PRMS, which differs from SEC reporting guidelines pursuant to which component of the financial reporting process, actual results could differ from certain information in the forepart of this annual report is presented. those estimates. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves An accounting policy is considered critical if it requires an accounting and cost estimates are recognized prospectively. Reserves are converted to estimate to be made based on assumptions about matters that are highly equivalent units on the basis of approximate relative energy content. uncertain at the time such estimate is made, and if different accounting estimates that reasonably could have been used, or changes in the Exploration costs Exploration costs consist of geosciences costs, including wages and salaries accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following and share-based compensation not subject to capitalization, write-offs accounting policies represent critical accounting policies as they involve a of unsuccessful exploration efforts, geological consultancy costs and costs higher degree of judgment and complexity in their application and require us relating to independent reservoir engineer studies. In particular, upon to make significant accounting estimates. The following descriptions of completion of the evaluation phase, a prospect is either transferred to oil critical accounting policies and estimates should be read in conjunction with and gas properties if it contains reserves, or is charged as exploration costs in our Consolidated Financial Statements and the accompanying notes and the period in which the determination is made. See “-Critical accounting other disclosures included elsewhere in this annual report. policies and estimates-Oil and gas accounting.” Administrative costs Administrative costs consist of corporate costs such as director fees and Business combinations Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair market value of the assets travel expenses, new project evaluations and back-office expenses principally acquired, equity instruments issued and liabilities incurred or assumed on the comprised of wages and salaries, share-based compensation, consultant fees date of completion of the acquisition. Acquisition costs incurred are expensed and other administrative costs, including certain costs relating to acquisitions. and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair market values at the acquisition date. The GeoPark 20F 133 excess of the cost of acquisitions over fair market value of a company’s share of the identifiable net assets acquired is recorded as goodwill. If the cost of Oil and gas accounting Oil and gas exploration and production activities are accounted for in the acquisition is less than a company’s share of the net assets required, the accordance with the successful efforts method on a field by field basis. We difference is recognized directly in the statement of income. account for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exploration The determination of fair value of identifiable acquired assets and assumed and evaluation costs until such time as the economic viability of producing liabilities means that we are to make estimates and use valuation techniques, the underlying resources is determined. Costs incurred prior to obtaining including independent appraisers. The valuation assumptions underlying legal rights to explore are expensed immediately to the income statement. each of these valuation methods are based on available updated information, including discount rates, estimated cash flows, market risk rates and other Exploration and evaluation costs may include: license acquisition, data. As a result, the process of identification and the related determination geological and geophysical studies (i.e., seismic), direct labor costs and of fair values require complex judgments and significant estimates. drilling costs of exploratory wells. No depreciation and/or amortization are charged during the exploration and evaluation phase. Upon completion Cash flow estimates for impairment assessments Cash flow estimates for impairment assessments require assumptions of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which about two primary elements: future prices and reserves. Estimates of future the determination is made, depending whether they have found reserves. prices require significant judgments about highly uncertain future events. If not developed, exploration and evaluation assets are written off after Historically, oil and natural gas prices have exhibited significant volatility. three years, unless it can be clearly demonstrated that the carrying value Our forecasts for oil and natural gas revenues are based on prices derived of the investment is recoverable. All field development costs are considered from future price forecasts among industry analysts, as well as our own construction in progress until they are finished and capitalized within assessments. Estimates of future cash flows are generally based on oil and gas properties, and are subject to depreciation once complete. Such assumptions of long-term prices and operating and development costs. costs may include the acquisition and installation of production facilities, The process of estimating reserves requires significant judgments and surveys for development purposes), project-related engineering and decisions based on available geological, geophysical, engineering the acquisition costs of rights and concessions related to proved properties. and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based Workovers of wells made to develop reserves and/or increase production on the D&M Reserves Report. Such estimates incorporate many factors are capitalized as development costs. Maintenance costs are charged to development drilling costs (including dry holes, service wells and seismic and assumptions including: • expected reservoir characteristics based on geological, geophysical and income when incurred. engineering assessments; Capitalized costs of proved oil and gas properties and production facilities • future production rates based on historical performance and expected future operating and investment activities; and machinery are depreciated on a licensed area by licensed area basis, using the unit of production method, based on commercial proved and • future oil and natural gas prices and quality differentials; probable reserves. The calculation of the “unit of production” depreciation • anticipated effects of regulation by governmental agencies; and takes into account estimated future finding and development costs, and • future development and operating costs. is based on current year-end un-escalated price levels. Changes in reserves Our management believes these factors and assumptions are reasonable to equivalent units on the basis of approximate relative energy content. based on the information available at the time we prepare our estimates. However, these estimates may change substantially as additional data from Oil and gas reserves for purposes of our Audited Consolidated Financial ongoing development activities and production performance becomes Statements are determined in accordance with PRMS, and were estimated available and as economic conditions impacting oil and natural gas prices by D&M, independent reserves engineers. and cost estimates are recognized prospectively. Reserves are converted and costs change. For further information relating to impairment of property, plant furniture and vehicles) not directly associated with oil and gas activities has and equipment, please see Note 38 to our audited consolidated financial been calculated by means of the straight line method by applying such Depreciation of the remaining property, plant and equipment assets (i.e., statements. 134 GeoPark 20F annual rates as required to write-off their value at the end of their estimated Non-market vesting conditions are included in assumptions in respect of useful lives. The useful lives range between three and 10 years. the number of options that are expected to vest. At each balance sheet date, Asset retirement obligations Obligations related to the plugging and abandonment of wells once operations are terminated may result in the recognition of significant we revise our estimates of the number of options that are expected to vest. We recognize the impact of the revision to original estimates, if any, in the statement of income, with a corresponding adjustment to equity. liabilities. We record the fair value of the liability for asset retirement The fair value of the share awards payments is determined at the grant date obligations in the period in which the wells are drilled. When the liability is by reference of the market value of the shares and recognized as an expense initially recognized, the cost is also capitalized by increasing the carrying over the vesting period. amount of the related asset. Over time, the liability is accreted to its present value at each reporting date, and the capitalized cost is depreciated When options are exercised, we issue new common shares. The proceeds over the estimated useful life of the related asset. Estimating the future received net of any directly attributable transaction costs are credited abandonment costs is difficult and requires management to make to share capital (nominal value) and share premium when the options are assumptions and judgments because most of the obligations will be settled exercised. after many years. Technologies and costs are constantly changing, as are political, environmental, health, safety and public relations considerations. Consequently, the timing and future cost of dismantling and abandonment Taxation The computation of our income tax expense involves the interpretation of are subject to significant modification. Any change in the variables applicable tax laws and regulations in many jurisdictions. The resolution of tax underlying our assumptions and estimates can have a significant effect on positions taken by us, through negotiations with relevant tax authorities or the liability and the related capitalized asset and future charges related through litigation, can take several years to complete and in some cases it is to the retirement obligations. The present value of future costs necessary for difficult to predict the ultimate outcome. well plugging and abandonment is calculated for each area on the basis of cash flows discounted at an average interest rate applicable to our company’s In addition, we have tax-loss carry-forwards in certain taxing jurisdictions indebtedness. The liability recognized is based upon estimated future that are available to offset against future taxable profit. However, deferred tax abandonment costs, wells subject to abandonment, time to abandonment, assets are recognized only to the extent that it is probable that taxable profit and future inflation rates. will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. Share-based payments We provide several equity-settled, share-based compensation plans to To the extent that actual outcomes differ from management’s estimates, certain employees and third-party contractors, composed of payments in the taxation charges or credits may arise in future periods. form of share awards and stock options plans. Fair value of the stock option plans for employee or contractor services Contingencies From time to time, we may be subject to various lawsuits, claims and received in exchange for the grant of the options is recognized as an expense. proceedings that arise in the normal course of business, including The total amount to be expensed over the vesting period, which is the employment, commercial, environmental and health & safety matters. For period over which all specified vesting conditions are to be satisfied, is example, from time to time, the Company receives notices of environmental, determined by reference to the fair value of the options granted calculated health and safety violations. Based on what our Management currently using the Black-Scholes model. Determining the total value of our share- knows, such claims are not expected to have a material impact on the based payments requires the use of highly subjective assumptions, including financial statements. the expected life of the stock options, estimated forfeitures and the price volatility of the underlying shares. The assumptions used in calculating the fair value of share-based payment represent management’s best estimates, Recent accounting pronouncements See note 2.1.1 to our Consolidated Financial Statements beginning on page but these estimates involve inherent uncertainties and the application of 189 to this Annual Report. management’s judgment. Results of operations The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our GeoPark 20F 135 Consolidated Financial Statements and the accompanying notes included elsewhere in this annual report. We acquired Winchester and Luna on February 14, 2012 and Cuerva on March 27, 2012. Accordingly, our results for the year ended December 31, 2014, 2013 and 2012 are not fully comparable with prior periods. Revenue Net oil sales For accounting purposes, the results of operations of Winchester, Luna and Net gas sales Cuerva were consolidated into our financial statements beginning Net revenue on January 31, 2012, January 31, 2012 and March 31, 2012, respectively. Production costs See Note 34 to our Annual Consolidated Financial Statements. In addition, we closed the acquisition of Brazilian Rio das Contas on March 31, 2014 and began consolidating its financials beginning on Gross profit Gross margin (%)(1) Exploration costs Administrative costs March 31, 2014. Accordingly, our results of operations for the year ended Selling expenses December 31, 2014, are not fully comparable with prior periods. Year ended December 31, 2014 compared to year ended December 31, 2013 The following table summarizes certain of our financial and operating data for the years ended December 31, 2014 and 2013. Impairment loss for non-financial assets Other operating (expense)/income Operating profit Financial results Profit before income tax Income tax Profit for the year Non-controlling interest Profit for the year attributable For the year ended % Change December 31, from prior 2014 2013 year (in thousands of US$, except for percentages) 367,102 61,632 428,734 (229,650) 315,435 22,918 338,353 (179,643) 199,084 158,710 46% (43,369) (48,164) (24,428) (9,430) (1,849) 71,844 (50,719) 21,125 (5,195) 15,930 8,418 47% (16,254) (46,584) (17,252) - 5,344 83,964 (33,876) 50,088 (15,154) 34,934 12,922 16% 169% 27% 28% 25% (1)% 167% 3% 42% 100% (135)% (14)% 50% (58)% (66)% (54)% (35)% to owners of the Company 7,512 22,012 (66)% 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$) Operating cost Royalties and other Production costs(2) Depreciation Total production cost Exploration costs Administrative costs Selling expenses 5,307 11,197 7,173 19,653 4,056 5,263 4,933 13,517 77.5 6.4 16.2 3.3 19.5 14.7 34.5 6.5 7.2 3.7 81.9 5.0 19.0 3.5 22.5 13.9 36.4 3.3 9.4 3.5 31% 112% 45% 45% (5)% 28% (15)% (6)% (13)% 6% (5)% 97% (23)% 6% (1) Gross margin is defined as total revenue minus production costs, divided by total revenue. (2) Calculated pursuant to FASB ASC 932. 136 GeoPark 20F The following table summarizes certain financial and operating data. Chile Colombia Brazil Other For the year ended December 31, 2014 Total Chile Colombia Other 2013 Total Net revenue Gross profit/(loss) Depreciation Impairment and write-off 145,720 68,096 (37,077) (28,772) 246,085 114,405 (52,713) (10,994) 35,621 15,919 (11,613) - 1,308 664 (254) (31) 428,734 199,084 (101,657) (39,797) 157,491 89,906 (30,471) (7,704) 179,324 67,612 (39,406) (3,258) (in thousands of US$) 1,538 1,192 (323) - 338,353 158,710 (70,200) (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 2013 (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) 145,720 246,085 35,621 1,308 157,491 179,324 - 1,538 (11,771) 66,761 35,621 (230) 428,734 338,353 90,381 (7)% 37% 100% (15)% 27% Consolidated Sale of crude oil Sale of gas Total By country Chile Colombia Brazil Other Total GeoPark 20F 137 Net revenue increased 27%, from US$338.4 million for the year ended Net revenue attributable to our operations in Brazil for the year ended December 31, 2013 to US$428.7 million for the year ended December 31, December 31, 2014 was US$35.6 million, representing 8% of our total 2014, primarily as a result of (i) incorporation of 9 months of results for consolidated sales, were related to our Rio das Contas operations and were Rio das Contas in our Brazil operations and (ii) an increase in volumes of crude composed of 96% gas sales, amounting to US$34.1 million. 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 Production costs The following table summarizes our production costs for the years ended December 31, 2014 compared to US$315.4 million for the year ended December 31, 2014 and 2013. December 31, 2013. In addition, sales of gas increased from US$22.9 million for the year ended December 31, 2013 to US$61.6 million for the year ended December 31, 2014 due to the incorporation of 9 months of sales for Rio das Contas, transaction that closed in March 31, 2014. For the year ended % Change December 31, from prior 2014 2013 year (in thousands of US$, except for percentages) The increase in 2014 net revenue of US$90.4 million is mainly explained by: • an increase of US$66.8 million in oil sales in Colombia. Consolidated (including Chile, Colombia, Argentina and Brazil) • an increase of U$S35.6 million in sales in Brazil, related to our Rio das Contas Depreciation operations and including US$1.5 million of oil sales and US$34.1 million of gas sales. Royalties Staff costs • a decrease of US$11.8 million in sales in Chile, including US$16.4 million. Transportation costs in oil sales, partially offset by an increase in gas sales of US$4.6 million. Well and facilities maintenance Net revenue attributable to our operations in Chile for the year ended Equipment rental December 31, 2014 was US$145.7 million, a 7% decrease from US$157.5 Other costs Consumables (99,360) (22,166) (17,731) (11,534) (25,475) (16,157) (7,563) (29,664) (68,579) (17,239) (14,202) (11,392) (20,662) (14,855) (7,139) (25,575) million for the year ended December 31, 2013, principally due to (1) Total (229,650) (179,643) 45% 29% 25% 1% 23% 9% 6% 16% 28% 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 2014 oil from US$84.3 per barrel for the year December 31, 2013 to US$89.4 per Chile Brazil Colombia 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 country Depreciation (35,856) (6,777) Royalties (11,553) (2,794) by lower international reference prices. The net decreased sales of crude Staff costs (4,026) oil were partially offset by a US$4.6 million increase in gas sales mainly driven Transportation 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. costs Well and facilities (6,784) maintenance (14,157) Net revenue attributable to our operations in Colombia for the year ended Consumables (2,111) December 31, 2014 was US$246.1 million, compared to US$179.3 million for Equipment the year ended December 31, 2013, representing 57% and 53% of our rental (97) - - - - - Year ended December 31, 2013(1) Colombia Chile (in thousands of US$) (51,856) (12,353) (13,962) (29,287) (7,384) (6,508) (39,233) (9,661) (8,988) (4,663) (6,456) (4,733) (10,969) (13,974) (8,163) (1,891) (12,105) (12,886) (7,433) - (7,139) (16,967) total consolidated sales. Such amounts were primarily due to increased sales Other costs (7,816) (5,355) (16,470) (7,896) of crude oil, from 2.4 mmbbl for the year ended December 31, 2013 to Total (77,624) (19,702) (131,680) (67,585) (111,712) 3.7 mmbbl for the year ended December 31, 2014, an increase of 54%. This increase resulted mainly from the development of the Tigana and Tua fields (1) No information is available for Brazil for 2013 as Rio das Contas was in the Llanos 34 Block. This was partially offset by a decrease in the average acquired in March 2014. realized prices per barrel of crude oil from US$80.3 per barrel to US$73.0 per barrel, primarily due to lower reference international prices. 138 GeoPark 20F Production costs increased 28%, from US$179.6 million for the year ended result, gross margin for the year ended December 31, 2014 was 46%, December 31, 2013 to US$229.7 million for the year ended December 31, which represented a slight decrease of 1% as compared to the gross margin 2014, primarily due to increased costs in the Colombian operations and the for the year ended December 31, 2013. Gross profit per boe decreased 7%, addition of US$19.7 million in such costs from our Brazilian operations to US$19.9 per barrel for the year ended December 31, 2014. related to the incorporation of 9 months of our Rio das Contas operations. Gross profit attributable to our operations in Chile for the year ended In our Chilean operations, production costs increased by 15%, due to higher December 31, 2014 was US$68.1 million, a 24% decrease from US$89.9 million depreciation charges per boe (that increased 41% to $17.5 per boe in 2014) for the year ended December 31, 2013. The contribution to our gross profit and the impact on fixed costs from lower oil and gas production and during such years from our operations in Chile was 34% and 57%, the startup of operations in the Tierra del Fuego Blocks. In the year ended respectively. Gross profit margin amounted to 47% for the year ended December 31, 2014, in Chile, operating costs per boe increased to US$16.7 December 31, 2014. 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 Gross profit attributable to our operations in Colombia for the year ended same period in 2013 it was 85.5% oil and 14.5% gas. December 31, 2014 was US$114.4 million a 69% increase from US$67.6 million for the year ended December 31, 2013. The contribution to our gross profit Production costs in Colombia increased 18%, to US$131.6 million for the year during such years from our operations in Colombia was 57% and 43%, ended December 31, 2014 as compared to the year ended December 31, respectively. Gross profit margin amounted to 46% for the year ended 2013, primarily due to increased production and deliveries in the year ended December 31, 2014. 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 Gross profit attributable to our operations in Brazil for the year ended boe for the year ended December 31, 2013, due to the fact that increased December 31, 2014 was US$15.9 million resulting from the acquisition of production generated improved fixed cost absorption, which positively Rio das Contas. The contribution to our gross profit during the year ended impacted the production costs per boe. In addition, depreciation charges per December 31, 2014 from our operations in Brazil was 8%. Gross profit boe decreased 17% to $14 per boe in 2014. margin amounted to 45% for the year ended December 31, 2014. Production costs in Brazil amounted to US$19.7 million for the year ended Exploration costs December 31, 2014 corresponding to our Rio das Contas operations. Operating costs per boe in decreased to US$6 per boe for the year ended December 31, 2014. Gross profit Year ended Chile Colombia December 31, Change from prior year Brazil 2014 2013 % (in thousands of US$, except for percentages) Other Total Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) (35,013) (4,567) (2,164) (1,625) (9,758) (3,341) (1,702) (1,453) (25,255) (1,226) (462) (172) (43,369) (16,254) (27,115) 259% 37% 27% 12% 167% Chile Colombia Brazil Other Total 68,096 114,405 15,919 664 89,906 67,612 - 1,192 (21,810) (24)% 46,793 15,919 (528) 69% Exploration costs increased 167%, from US$16.3 million for the year ended 100% (44)% December 31, 2013 to US$43.4 million for the year ended December 31, 2014, primarily as the result of an increase in recognition of write-offs of 199,084 158,710 40,374 25% unsuccessful efforts primarily in our Chilean operations in an amount of US$19.4 million and to a lesser extent due to increased staff costs Gross profit increased 25%, from US$158.7 million for the year ended amounting to US$5.3 million. December 31, 2013 to US$199.1 million for the year ended December 31, 2014, as a result of (i) increased sales and production in Colombia, (ii) the The 2014 charge in write-off of unsuccessful efforts corresponds to the cost incorporation of nine months corresponding to our Rio das Contas operations of ten unsuccessful exploratory wells: eight of them in Chile (three in the in Brazil in the year ended December 31, 2014, partially offset by decreased Flamenco Block, two in the Fell Block, two in the Tranquilo Block and one in net revenues and higher production costs in our Chilean operations. As a the Campanario Block) and two of them in Colombia (in the non-operated GeoPark 20F 139 Arrendajo Block). The 2014 charge also includes the loss generated by the Selling expenses write-off of the remaining seismic cost for Otway and Tranquilo Blocks, registered in previous years. The 2013 charge in write-off of unsuccessful efforts corresponds to the cost of five unsuccessful exploratory wells: two in Chile (one in the Fell Block and one in the Tranquilo Block) and three in Colombia (one well in the Cuerva Block and one well in each of the non-operated blocks of Arrendajo and Llanos 32). Administrative costs Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) (2,470) (21,456) - (502) (4,062) (12,677) - (513) 1,592 (8,779) - 11 (24,428) (17,252) (7,176) (39)% 69% - (2)% 42% Chile Colombia Brazil Other Total Year ended December 31, 2014 2013 Change from prior year % Selling expenses increased 42%, from US$17.3 million for year ended (in thousands of US$, except for percentages) December 31, 2013 to US$24.4 million for the year ended December 31, 2014, Chile Colombia Brazil Other Total (19,401) (11,965) (2,819) (13,979) (16,420) (16,409) (1,404) (12,351) (2,981) 4,444 (1,415) (1,628) (48,164) (46,584) (1,580) 18% primarily due to increased production and deliveries in our Colombian 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. (27)% 101% 13% 3% Operating profit (loss) Administrative costs increased 3%, from US$46.6 million for the year ended December 31, 2013 to US$48.2 million for the year ended December 31, 2014, primarily as a result of an increase in costs in: (1) our Chilean operations, from US$16.4 million in the year ended December 31,2013 to US$19.4 million in the year ended December 31, 2014, mainly due to the startup of our operations in Tierra del Fuego; (2) incorporation of our Rio das Contas Chile operations in Brazil and (3) higher corporate expenses related to our growth Colombia strategy and new business efforts, partially offset by lower administrative expenses in Colombia. Brazil Other Total Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) 11,733 67,212 10,658 (17,759) 71,844 63,110 38,811 (3,107) (14,850) (51,377) 28,401 13,765 (2,909) 83,964 (12,120) (81)% 73% 443% 20% (14)% We recorded an operating profit of US$71.8 million for the year ended December 31, 2014, a 14% decrease from US$84.0 million for the year ended December 31, 2013, primarily due to lower gross profit and higher exploratory costs resulting from the write-offs of unsuccessful exploratory wells in our 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 non-financial assets amounting to $9.4 million related to our La Cuerva Block, resulting from the decrease in international oil prices. 140 GeoPark 20F Financial results, net Financial loss increased 50% to US$50.7 million for the year ended December Income tax 31, 2014 as compared to US$33.9 million for the year ended December 31, 2013, due to exchange rate differences amounting to US$22 million resulting 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 Chile issuance costs in connection with the redemption of the Notes due 2015 in Colombia an amount of US$8.6 million following the issuance of Notes due 2020 in February 2013. Profit before income tax Brazil Other Total Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) 4,080 (4,121) (21,415) (17,870) 7,446 4,694 528 6,309 (5,195) (15,154) 8,201 (3,545) 6,918 (1,615) 9,959 (199)% 20% 1,310% (26)% (66)% Income tax decreased 66%, from US$15.2 million for the year ended Year ended December 31, 2013 to US$5.2 million for the year ended December 31, 2014, December 31, Change from prior year as a result of our decreased results of operations in Chile and Brazil, partially 2014 2013 % offset by higher results of operations in our Colombian operations. (in thousands of US$, except for percentages) Our effective tax rate for the year ended December 31, 2014 was 25% as Chile Colombia Brazil Other Total 13,151 61,609 (9,698) (43,937) 21,125 49,965 31,049 (1,937) (36,814) (74)% compared to 30% in the year ended December 31, 2013 due to higher 30,560 (7,761) 98% charges from deferred income taxes in the year ended December 31, 2014 401% mainly resulting from the effect of currency translation on tax base. (28,989) (14,948) 52% 50,088 (28,963) (58)% Profit for the year For the year ended December 31, 2014, we recorded a profit before income tax of US$21.1 million, a decrease of 58% from US$50.1 million for the year ended December 31, 2013, primarily due lower profits from our Chilean, Brazilian and Other operations amounting to US$36.8 million, US$7.8 million and US$14.9 million, respectively, partially offset by increased profits from Chile our Colombian operations amounting to US$30.6 million. Colombia Brazil Other Total Year ended December 31, Change from prior year 2014 2013 % (in thousands of US$, except for percentages) 17,231 40,194 (2,252) (39,243) 15,930 45,844 13,179 (1,409) (28,613) 27,015 (843) (22,680) (16,563) 34,934 (19,004) (62)% 205% 60% 73% (54)% For the year ended December 31, 2014, we recorded a profit of US$15.9 million, a 54% decrease from US$34.9 million for the year ended December 31, 2013, as a result of the reasons described above. Profit for the year attributable to owners of the Company Profit for the year attributable to owners of the Company decreased by 66% to US$7.5 million, for the reasons described above. Profit attributable to non-controlling interest decreased by 35% to US$8.4 million for the year ended December 31, 2014 as compared to the prior year. GeoPark 20F 141 Year ended December 31, 2013 compared to year ended December 31, 2012 The following table summarizes certain of our financial and operating data For the year ended % Change December 31, from 2013 2012 prior year for the years ended December 31, 2013 and 2012. (in thousands of US$, except for percentages) Revenue Net oil sales Net gas sales Net revenue Production costs Gross profit Gross margin (%)(1) Exploration costs Administrative costs Selling expenses Other operating income/(expense) Operating profit Financial income Financial expenses Bargain purchase gain on acquisition of subsidiaries Profit before income tax Income tax Profit for the year Non-controlling interest 315,435 221,564 22,918 28,914 338,353 (179,643) 250,478 (129,235) 158,710 121,243 47% (16,254) (46,584) (17,252) 5,344 83,964 4,893 48% (27,890) (28,798) (24,631) 823 40,747 892 (38,769) (17,200) - 50,088 (15,154) 34,934 12,922 8,401 32,840 (14,394) 18,446 6,567 42% (21)% 35% 39% 31% (1)% (42)% 62% (30)% 549% 106% 449% 125% - 53% 5% 89% 97% Profit for the year attributable to owners of the Company 22,012 11,879 85% Net production volumes Oil (mbbl) Gas (mcf) Total net production (mboe) 4,056 5,263 4,933 2,513 8,346 3,904 Average net production (boepd) 13,517 11,292 Average realized sales price Oil (US$per bbl) Gas (US$per mmcf) Average unit costs per boe (US$) Operating cost Royalties and other Production costs(2) Depreciation Total production cost Exploration costs Administrative costs Selling expenses 81.9 5.0 19.0 3.5 22.5 13.9 36.4 3.3 9.4 3.5 90.5 4.0 16.8 2.9 19.7 13.4 33.1 7.1 7.4 6.3 61% (37)% 26% 20% (10)% 25% 13% 21% 14% 4% 10% (54)% 27% (44)% (1) Gross margin is defined as total revenue minus production costs, divided by total revenue. (2) Calculated pursuant to FASB ASC 932. 142 GeoPark 20F The following table summarizes certain financial and operating data. Net revenue Gross profit/(loss) Depreciation Impairment and write-off Chile Colombia Other 157,491 89,906 (30,471) (7,704) 179,324 67,612 (39,406) (3,258) 1,538 1,192 (323) - 2013 Total 338,353 158,710 (70,200) (10,962) For the year ended December 31, Chile Colombia Other 2012 Total 149,927 84,133 (28,734) (18,490) 99,501 39,304 (21,050) (5,147) (in thousands of US$) 1,050 (2,194) (3,533) (1,915) 250,478 121,243 (53,317) (25,552) Net revenue US$28.9 million for the year ended December 31, 2012 to US$22.9 million for For the year ended December 31, 2013, crude oil sales were our principal source of revenue, with 93% and 7% of our total revenue from crude oil and gas sales, respectively. The following chart shows the change in oil and The increase in 2013 net revenue of US$87.8 million is mainly explained by: • an increase of US$79.8 million in oil sales in Colombia. natural gas sales from the year ended December 31, 2012 to the year ended • an increase of US$13.6 million in oil sales in Chile, partially offset by a December 31, 2013. decrease of US$6.0 million in gas deliveries in Chile. the year ended December 31, 2013. Consolidated Sale of crude oil Sale of gas Total By country Chile Colombia Other Total For the year ended December 31, Net revenue attributable to our operations in Chile for the year ended 2013 2012 December 31, 2013 was US$157.5 million, a 5% increase from (in thousands of US$) US$149.9 million for the year ended December 31, 2012, principally due to (1) increased sales of crude oil of 1,592 mbbl for the year ended December 315,435 221,564 31, 2013 compared to 1,415 mbbl for the year ended December 31, 2012 22,918 28,914 (an increase of 12.5%) due to the continuing development in the Tobifera 338,353 250,478 formation, and (2) decreased average realized prices per barrel of crude oil from US$85.4 per barrel for the year December 31, 2012 to US$84.3 per barrel for the year ended December 31, 2013 (a decrease of US$1.1 per barrel Year ended or a total of 1.3%). The decrease in the average realized price per barrel December 31, 2012 2013 Change from prior year % was partly attributable to quality discounts in the year ended December 31, 2013 as compared to the same period in 2012. The net increased sales of (in thousands of US$, except for percentages) crude oil were partially offset by a US$6.0 million reduction in gas sales mainly 157,491 179,324 1,538 149,927 99,501 1,050 7,564 79,823 488 338,353 250,478 87,875 5% 80% 46% 35% driven by a decrease of 37% in production in the year ended December 31, 2013, partially compensated by higher average gas prices. The contribution to our net revenue during such years from our operations in Chile was 47% and 60%, respectively. Net revenue attributable to our operations in Colombia for the year ended Net revenue increased 35%, from US$250.5 million for the year ended December 31, 2013 was US$179.3 million, compared to US$99.5 million December 31, 2012 to US$338.4 million for the year ended December 31, for the year ended December 31, 2012, representing 53% and 40% of our 2013, primarily as a result of an increase in volumes of crude sales by 55%. total consolidated sales. Such amounts were primarily due to increased Sales of crude oil in operated blocks increased to 3,800 mbbl in the year sales of crude oil in operated blocks, from 1,087 mbbl for the year ended ended December 31, 2013 compared to 2,448 mbbl in the year ended December 31, 2012 to 2,185 mbbl for the year ended December 31, 2013, an December 31, 2012, and resulted in net revenue of US$315.4 million for the increase of 101%. This increase resulted from (i) the incorporation of an year ended December 31, 2013 compared to US$221.6 million for the year additional three months of Cuerva’s results in the year ended December 31, ended December 31, 2012, partially offset by decreases in sales of gas from 2013 and the incorporation of an additional month of Winchester and GeoPark 20F 143 Luna’s operations (the revenues for the corresponding period that were not Production costs increased 39%, from US$129.2 million for the year ended included in the year ended December 31, 2012 amounted to US$23.8 million) December 31, 2012 to US$179.6 million for the year ended December 31, as compared to the same period in 2012, and (ii) the development of the 2013, primarily due to the addition of US$51.5 million in such costs from our Max and Tua fields and our discoveries of the Tarotaro field in the Llanos 34 Colombian operations. Block and the Potrillo field in the Yamú Block. This was partially offset by a decrease in the average realized prices per barrel of crude oil from US$97.1 In our Chilean operations, production costs increased by 2.7%, due to per barrel to US$80.3 per barrel, primarily due to the fact that in 2013 we the change in revenue mix from gas to oil, which has higher production costs started selling part of our oil production at well-head with higher commercial than gas, and due to an increase in our oil production. In the year ended discounts, as opposed to transporting it to different delivery points, which December 31, 2013, in Chile, operating costs per boe increased to US$12.2 led to lower selling expenses that offset the lower selling prices. per boe from US$10.7 per boe in 2012. In the year ended December 31, 2013, Production costs the revenue mix for Chile was 85.5% oil and 14.5% gas, whereas for the same period in 2012 it was 80.7% oil and 19.3% gas. The following table summarizes our production costs for the years ended Operating costs in Colombia increased 79.1%, to US$62.8 million for the year December 31, 2013 and 2012. ended December 31, 2013 as compared to the year ended December 31, 2012, primarily due to an increase in production and deliveries the region and For the year ended % Change also to the incorporation of an additional three months of Cuerva’s results December 31, from prior in the year ended December 31, 2013 and the incorporation of an additional 2013 2012 year month of Winchester and Luna’s operations in Colombia (operating costs (in thousands of US$, except for percentages) for the corresponding period that were not included in the year ended Consolidated (including Chile, Colombia and Argentina) Depreciation Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (68,579) (17,239) (14,202) (11,392) (20,662) (14,855) (7,139) (25,575) (52,307) (11,424) (14,171) (7,211) (9,385) (9,884) (5,936) (18,917) (179,643) (129,235) 120% Gross profit 50% 20% 35% 39% December 31, 2012 amounted to US$14.2 million). However, operating costs per boe in Colombia decreased to US$26.5 per boe for the year ended December 31, 2013 from US$34.0 per boe for the year ended December 31, 2012, due to the fact that increased production generated improved fixed cost absorption, which positively impacted the production costs per boe. 31% 51% 0% 58% Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) 89,906 67,612 1,192 84,133 39,304 (2,194) 158,710 121,243 5,773 28,308 3,386 37,467 7% 72% 154% 31% Year ended December 31, Colombia Chile 2013 2012 Chile Colombia Chile Colombia Other Total (in thousands of US$) By country Depreciation Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total 144 GeoPark 20F Gross profit increased 31%, from US$121.2 million for the year ended (29,287) (39,233) (28,120) (20,964) December 31, 2012 to US$158.7 million for the year ended December 31, (7,384) (6,508) (6,456) (8,163) (1,891) - (9,661) (8,988) (4,733) (12,105) (12,886) (7,139) (7,088) (8,560) (5,986) (6,290) (2,717) - (4,164) (7,432) (1,045) (2,850) (7,090) (5,936) 2013, as a result of (i) increased sales and production in Colombia, (ii) the incorporation of an additional three months of Cuerva’s results in the year ended December 31, 2013 and the incorporation of an additional month of Winchester and Luna’s operations in Colombia (gross profit for the corresponding period that was not included in the year ended December 31, 2012 amounted to US$9.4 million) and (iii) increased net revenues in our Chilean operations. As a result, gross margin for the year ended December 31, (7,896) (16,967) (7,033) (10,716) 2013 was 47%, which represented a slight decrease of 3% as compared to (67,585) (111,712) (65,794) (60,197) the gross margin for the year ended December 31, 2012. Gross profit per boe increased 4%, to US$32.2 per barrel for the year ended December 31, 2013. Gross profit attributable to our operations in Chile for the year ended Administrative costs increased 62%, from US$28.8 million for the year ended December 31, 2012 was US$89.9 million, a 7% increase from US$84.1 million December 31, 2012 to US$46.6 million for the year ended December 31, 2013, for the year ended December 31, 2012. The contribution to our gross primarily as a result of an increase in costs in: (1) our Chilean operations, profit during such years from our operations in Chile was 57% and 69%, from US$10.9 million in the year ended December 31,2012 to US$16.4 million respectively. in the year ended December 31, 2013, mainly due to (1) the startup of our operations in Tierra del Fuego; (2) increased staff and other costs in Colombia, Gross profit attributable to our operations in Colombia for the year ended and (3) higher corporate expenses related to our growth strategy and new December 31, 2012 was US$67.6 million a 72% increase from US$39.3 million business efforts. for the year ended December 31, 2012. The contribution to our gross profit during such years from our operations in Colombia was 43% and 32%, Selling expenses respectively. Exploration costs Chile Colombia Other Total Year ended December 31, Change from prior year Chile 2013 2012 % Colombia (in thousands of US$, except for percentages) (9,758) (3,341) (3,155) (20,452) 10,694 (5,528) (1,910) 2,187 1,245 Other Total (52)% (40%) Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) (4,062) (5,327) (12,677) (18,953) (513) (351) (17,252) (24,631) 1,265 6,276 162 7,379 (24)% (33)% (46)% (30)% (16,254) (27,890) 11,636 (42)% December 31, 2012 to US$17.3 million for the year ended December 31, 2013, primarily due to the change in the delivery point for certain of our production 65% Selling expenses decreased 30%, from US$24.6 million for year ended Exploration costs decreased 42%, from US$27.9 million for the year ended in our Colombian operations. In our Chilean operations, selling expenses December 31, 2012 to US$16.3 million for the year ended December 31, were 24% lower compared to prior year, primarily as a result of the impact 2013, primarily as the result of the decrease in recognition of write-offs of of the DOP penalty we paid to Methanex in 2012, described in “-Business- unsuccessful efforts in an amount of US$14.6 million. Marketing and Delivery Commitments,” partially offset by the increase in oil The 2013 charge in write-off of unsuccessful efforts corresponds to the cost of five unsuccessful exploratory wells: two in Chile (one in Fell Block and Operating profit (loss) deliveries in Chile. one in Tranquilo Block) and three in Colombia (one well in Cuerva Block and one well in each of the non-operated blocks, Arrendajo and Llanos 32). The 2012 charge in write-off of unsuccessful efforts corresponds to the costs of eight unsuccessful exploratory wells: five in Chile (two in Fell Block, two in Otway Block and the remaining in Tranquilo Block) and three in Colombia (one well in Cuerva Block, one well in Arrendajo Block and the remaining in Chile Llanos 17 Block). The 2012 charge also includes the loss generated by the Colombia relinquishment of an area in the Del Mosquito Block in Argentina. Other Total Administrative costs Year ended December 31, 2013 2012 Change from prior year % (in thousands of US$, except for percentages) 63,110 38,811 (17,957) 83,964 47,915 8,499 (15,667) 40,747 15,195 30,312 (2,290) 43,217 32% 357% 15% 106% Year ended December 31, 2013, a 106% increase from US$40.8 million for the year ended December 31, Change from prior year December 31, 2012, primarily due to the incorporation of an additional three 2013 2012 % months of Cuerva’s results and an increase in production and deliveries We recorded an operating profit of US$84.0 million for the year ended Chile Colombia Other Total (in thousands of US$, except for percentages) 51% (10,879) (5,541) (16,420) in Colombia in the year ended December 31, 2013 and the incorporation of an additional month of Winchester and Luna’s operations in Colombia. In (16,409) (13,755) (7,393) (10,526) (46,584) (28,798) (9,016) (3,229) 17,786 121% addition, during the year ended December 31, 2013, in Chile, we recognized a gain amounting to US$3.2 million in other operating income related to the 31% 62% GeoPark 20F 145 reversal of certain provisions previously recorded that, based on the view Income tax of our management and legal advisors, were extinguished as the statute of limitations was reached. Financial results, net Financial loss increased 108% to US$33.9 million, due to the accelerated Chile amortization of debt issuance costs incurred in connection with the Colombia redemption of the Notes due 2015 in an amount of US$8.6 million following the issuance of the Notes due 2020 in February 2013, the incorporation of an additional three months of Cuerva’s results in the year ended December Other Total Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) (4,121) (11,349) (17,870) 6,837 (4,976) 1,931 (15,154) (14,394) 7,228 (12,894) 4,906 (760) (64)% 259% 254% 5% 31, 2013 and the incorporation of an additional month of Winchester and Income tax increased 5%, from US$14.4 million for the year ended Luna’s operations in Colombia into our results and higher interest expenses December 31, 2012 to US$15.2 million for the year ended December 31, 2013, generated by the issuance of the Notes due 2020 in an amount of US$12.1 as a result of our increased results of operations in Chile and Colombia. million, partially offset by interest income due to increased cash and cash Our effective tax rate for the year ended December 31, 2013 was 30% as equivalents. Profit before income tax compared to 44% in the year ended December 31, 2012 due to lower charges from deferred income taxes in the year ended December 31, 2013 mainly resulting from the effect of currency translation on tax base in Colombia and Chile, compensated by an increase in current taxes resulting Year ended from higher profits in Chile and Colombia and the impact of tax loss carry December 31, Change from prior year forwards recorded in Colombia. 2013 2012 % (in thousands of US$, except for percentages) Profit for the year Chile Colombia Other Total 49,965 31,049 42,272 11,223 7,693 19,826 (30,926) (20,655) (10,271) 50,088 32,840 17,248 18% 177% 50% 53% For the year ended December 31, 2013, we recorded a profit before income Chile tax of US$50.1 million, an increase of 53% from US$32.8 million for the year Colombia ended December 31, 2012, primarily due to the incorporation of an additional Other three months of Cuerva’s results in the year ended December 31, 2013 and the incorporation of an additional month of Winchester and Luna’s Total Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) 45,844 13,179 (24,089) 34,934 30,923 6,247 (18,724) 18,446 14,921 6,932 (5,365) 16,488 48% 111% 29% 89% operations in Colombia into our results and to increases in production and For the year ended December 31, 2013, we recorded a profit of US$34.9 deliveries in Colombia, and, to a lesser extent, higher profits from our Chilean million, a 89% increase from US$18.5 million for the year ended December 31, operations, partially offset by the occurrence of two non-recurring events: 2012, as a result of the reasons described above. (1) accelerated amortization of debt issuance costs described above; and (2) the comparative effect of a bargain purchase gain on acquisition of subsidiaries of US$8.4 million as a result of the acquisitions of Winchester Profit for the year attributable to owners of the Company Profit for the year attributable to owners of the Company increased by and Luna recorded in the year ended December 31, 2012. 85% to US$22.0 million, for the reasons described above. Profit attributable to non-controlling interest increased by 97% to US$12.9 million for the year ended December 31, 2013 as compared to the prior year due to the incorporation of an additional three months of Cuerva’s results in the year ended December 31, 2013 and the incorporation of an additional month of Winchester and Luna’s operations in Colombia and an increase in non-controlling interest resulting from LGI’s acquisition of a 20% equity interest in our Colombian operations. 146 GeoPark 20F B. Liquidity and capital resources Overview Our financial condition and liquidity is and will continue to be influenced by a variety of factors, including: (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 six-month LIBOR + 4.0%. • our ability to generate cash flows from our operations; In February, 2013, we issued US$300.0 million aggregate principal amount • our capital expenditure requirements; of senior secured notes due 2020. The Notes due 2020 mature on February • the level of our outstanding indebtedness and the interest we are obligated 11, 2020 and bear interest at a fixed rate of 7.50% and a yield of 7.625% to pay on this indebtedness; and per annum. Interest on the Notes due 2020 is payable semi-annually in arrears • changes in exchange rates which will impact our generation of cash flows on February 11 and August 11 of each year. Our notes due 2020 contain from operations when measured in U.S. dollars, and, upon the completion of limitations on the amount of indebtedness we can incur. At current prices, our Brazil Acquisitions, the real. absent certain customary exceptions, we do not anticipate achieving an EBITDA (as defined in the indenture governing our notes due 2020) during Our principal sources of liquidity have historically been contributed fiscal year 2015 that would be sufficient enough to allow us to incur shareholder equity, debt financings and cash generated by our operations. additional indebtedness, other than certain categories and small baskets of permitted debt, as specified in the indenture. Since 2005 to 2014, we have raised approximately US$200 million in equity offerings at the holding company level and more than US$557 million We believe that our current operations and 2015 capital expenditures through debt arrangements with multilateral agencies such as the IFC, gas program can be funded from cash flow from existing operations and cash on prepayment facilities with Methanex, international bond issuances and hand. Should our operating cash flow decline due to unforeseen events, bank financings, described further below, which have been used to fund our including delivery restrictions or a protracted downturn in oil and gas prices, capital expenditures program and acquisitions and to increase our liquidity. we would examine measures such as further capital expenditure program reductions, pre-sale agreements, disposition of assets, or issuance of equity, We have also raised US$173.3 million to date through our strategic among others. partnership with LGI following the sale of minority interests in our Colombian and Chilean operations. Capital expenditures We have funded our capital expenditures with proceeds from equity We initially funded our 2012 expansion into Colombia through a offerings, credit facilities, debt issuances and pre-sale agreements, as well US$37.5 million loan, cash on hand and a subsequent sale of a minority as through cash generated from our operations. We expect to incur interest in our Colombian operations to LGI. We subsequently restructured substantial expenses and capital expenditures as we develop our oil and our outstanding debt in February 2013, by issuing US$300.0 million natural gas prospects and acquire additional assets. aggregate principal amount of Notes due 2020, a portion of the proceeds of which we used to prepay the US$37.5 million loan and to redeem all of our In the year ended December 31, 2013, we made total capital expenditures of outstanding Notes due 2015. See “-Item 4. Information on the Company-B. US$228.0 million (US$145.7 million, US$82.1 million and US$0.2 million in Chile, Business Overview-Significant Agreements-Agreements with LGI.” Colombia and Argentina, respectively), consisting of US$133.3 million related to exploration. 39 new wells were drilled (17 in Chile and 22 in Colombia) In February 2014, we commenced trading on the NYSE and raised in blocks in which we have working interests and/or economic interests. US$98 million (before underwriting commissions and expenses), including In addition to the above, in 2013 we completed approximately 1,350 sq. km. the over allotment option granted to and exercised by the underwriters, in 3D seismic surveys (more than 1,100 sq. km in Chile, mainly related to the through the issuance of 13,999,700 common shares. blocks located in Tierra del Fuego and over 250 sq. km in Colombia). In the year ended December 31, 2012, we made total capital expenditures of US$303.5 In March 2014, we borrowed US$70.5 million pursuant to a five-year term million, which consisted of investments of US$105.3 million relating to the (including annual principal amortization in March and September of each purchase price for our acquisitions of Winchester, Luna and Cuerva in Colombia year starting in 2015) variable interest secured loan, secured by the benefits and other investments of US$198.2 million, including the drilling of 45 new GeoPark receives under the Purchase and Sale Agreement for Natural Gas wells and seismic surveys registered, principally in our Tierra del Fuego Blocks. with Petrobras, equal to six-month LIBOR + 3.9% to finance part of the purchase price of our Rio das Contas acquisition, and funded the remaining In the year ended December 31, 2014, we made total capital expenditures of amount with cash on hand. In March 2015, we reached an agreement to: US$238.0 million (US$161 million, US$66 million, and US$11 million in Chile, GeoPark 20F 147 Colombia and Brazil, respectively), consisting of US$110 million related to exploration. 53 new wells were drilled (32 in Chile, and 21 in Colombia in Cash flows provided by financing activities Cash provided by financing activities was US$124.7 million for the year blocks in which we have working interests and/or economic interests. ended December 31, 2014, compared to cash provided by financing activities In addition to the above, in 2014 we completed the acquisition of Rio das of US$164.0 million for the year ended December 31, 2013. This change Contas for US$115 million (net of cash acquired). was principally the result of cash received in the 2013 period from the Cash flows The following table sets forth our cash flows for the periods indicated: early redemption of our Notes due 2015 and the repayment of the Banco Itaú BBA Credit Agreement, in an aggregate amount of US$175.0 million) issuance of US$300.0 million of our Notes due 2020 (partially offset by the and an increase of US$36.6 million in cash from LGI pertaining principally to Year ended December 31, its investment in our Colombian and Chilean operations. These were 2014 2013 2012 partially offset by funds recovered from our initial public offering and listing (in thousands of US$) of our common shares on the New York Stock Exchange in February 2014 amounting to US$90.9 million and the $70.5 million loan entered into 230,746 127,295 129,427 with Itaú BBA International plc used to fund the Rio das Contas acquisition. (344,041) (208,500) (301,132) 124,716 164,018 26,375 Cash provided by financing activities was US$164.0 million for the year Cash flows provided by (used in) Operating activities Investing activities Financing activities Net increase (decrease) in cash ended December 31, 2013, compared to cash provided by financing activities and cash equivalents 11,421 82,813 (145,330) of US$26.4 million for the year ended December 31, 2012. This change was Cash flows provided by operating activities For the year ended December 31, 2014, cash provided by operating activities principally the result of cash received in the 2013 period from the issuance of US$300.0 million of our Notes due 2020 and an increase of US$36.6 million in cash from LGI pertaining principally to its investment in our Colombian was US$230.7 million, a 81.3% increase from US$127.3 million for the year and Chilean operations. These were partially offset by the early redemption ended December 31, 2013. of our Notes due 2015 and the repayment of the Banco Itaú BBA Credit Agreement, in an aggregate amount of US$175.0 million. For the year ended December 31, 2013, cash provided by operating activities was US$127.3 million, a 6.3% decrease from US$129.4 million for the year ended December 31, 2012. This increase is mainly driven by higher Indebtedness As of December 31, 2014 and 2013, we had total outstanding indebtedness of production and revenues that we obtained during 2014, partially offset by US$369.6 million and US$317.1 million, respectively, as set forth in the table higher associated costs. below. Cash flows used in investing activities For the year ended December 31, 2014, cash used in investing activities was US$344.0 million, a 64.9% increase from US$208.5 million for the year ended December 31, 2013. This increase was primarily related to our Brazilian acquisitions, which occurred in the first quarter of 2014. This amount was complemented by an increase of US$22.8 million in capital expenditures relating to the drilling of 53 new wells (32 in Chile and 21 in Colombia) and facilities construction, as compared to the drilling of 39 wells (17 in Chile and 22 in Colombia) for the year ended December 31, 2013. Cash used in investing activities decreased by US$92.6 million during the BCI Loans(1) Bond GeoPark Latin America Agencia en Chile (Notes due 2020) Banco de Chile(2) Rio das Contas Credit Facility Overdrafts(3) Total As of December 31, 2014 2013 (in thousands of US$) 90 2,143 300,963 - 68,540 - 299,912 15,002 - 30 369,593 317,087 year ended December 31, 2013, from US$301.1 million in 2012 to US$208.5 (1) Facility to establish the operational base in the Fell Block. million in 2013. This decrease includes US$105.3 million related to the (2) Short-term financing obtained in December 2013 and fully repaid in purchase price for our Colombian operations (net of cash acquired) in 2012; January 2014. this amount was partially offset by an increase of US$19.4 million in capital (3) We have been granted credit lines for over US$69 million as of December expenditures relating to the drilling of 39 new wells (17 in Chile and 22 31, 2014. The incurrence of debt under these credit lines could be limited in Colombia), as compared to the drilling of 35 wells (20 wells in Chile and by debt covenants associated with our other debt documents. 24 in Colombia) for the year ended December 31, 2012. 148 GeoPark 20F Our material outstanding indebtedness as of December 31, 2014 is described of the principal amount of such Notes due 2020 plus an applicable “make- below. Notes due 2020 whole” premium, plus accrued and unpaid interest (including, additional amounts), if any, as such term is defined in the indenture governing the Notes due 2020, if any, to the redemption date. General On February 11, 2013, we issued US$300.0 million aggregate principal At any time and from time to time on or after February 11, 2017, we may, at our option, redeem all or part of the Notes due 2020, at the redemption amount of senior secured notes due 2020. The Notes due 2020 mature on prices, expressed as percentages of principal amount, set forth below, February 11, 2020 and bear interest at a fixed rate of 7.50% and a yield of plus accrued and unpaid interest thereon (including additional amounts), 7.625% per annum. Interest on the Notes due 2020 is payable semi-annually if any, to the applicable redemption date, if redeemed during the 12-month in arrears on February 11 and August 11 of each year. period beginning on February 11 of the years indicated below: Ranking 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 Year 2017 2018 equally in right of payment with all senior existing and future obligations 2019 and after of Agencia (except those obligations preferred by operation of Bermuda and Percentage 103.750% 101.875% 100.000% Chilean law, including, without limitation, labor and tax claims); effectively In addition, at any time prior to February 11, 2016, we may, at our option, senior to all unsecured debt of Agencia and GeoPark Latin America, to the redeem up to 35% of the aggregate principal amount of the Notes due extent of the value of the collateral; senior in right of payment to all existing 2020 (including any additional notes) at a redemption price of 107.50% of and future subordinated indebtedness of Agencia and GeoPark Latin America; the principal amount thereof, plus accrued and unpaid interest (including and effectively junior to any future secured obligations of Agencia and its additional amounts) if any to the redemption date, with the net cash subsidiaries (other than additional notes issued pursuant to the indenture proceeds of one or more equity offerings; provided that: (1) Notes due 2020 governing the Notes due 2020) to the extent secured by assets constituting in an aggregate principal amount equal to at least 65% of the aggregate with a security interest on assets not constituting collateral, in each case to principal amount of Notes due 2020 issued on the first issue date remain the extent of the value of the collateral securing such obligations. outstanding immediately after the occurrence of such redemption; and (2) the redemption must occur within 90 days of the date of the closing of Guarantees The Notes due 2020 are guaranteed unconditionally on an unsecured basis by such equity offering. us, all of our wholly-owned subsidiaries, and any subsidiary that guarantees any of our debt, subject to certain exceptions. Collateral The notes are secured by a first-priority perfected security interest in certain Change of control Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2020, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts collateral, which consists of: 80% of the equity interests of each of GeoPark payable in respect thereof) thereon to the date of purchase. Chile and GeoPark Colombia held by Agencia, and loans of the net proceeds of the Notes due 2020 made by Agencia to each of GeoPark Fell and GeoPark Llanos SAS. Except for certain immaterial subsidiaries and other exceptions, Covenants The Notes due 2020 contain customary covenants, which include, among GeoPark and Agencia are also required to pledge the equity interests of our others, limitations on: the incurrence of debt and disqualified or preferred subsidiaries. stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, transfer, prepayment or modification The Notes due 2020 are also secured on a first-priority basis by intercompany of certain collateral, guarantees of additional indebtedness, the ability of loans, disbursed to subsidiaries, in an aggregate amount at any one time that certain subsidiaries to pay dividends, asset sales, transactions with affiliates, does not exceed US$300.0 million. Optional redemption At any time prior to February 11, 2017, we may, at our option, redeem any of the Notes due 2020, in whole or in part, at a redemption price equal to 100% engaging in certain businesses, and merger or consolidation with or into another company. As of December 31, 2014, we were in compliance with the above mentioned covenants. GeoPark 20F 149 In the event the Notes due 2020 receive investment-grade ratings from pledge by us to BCI of the seismic equipment acquired to start the operations at least two of the following rating agencies, Standard & Poor’s Rating Group, in these new blocks. The BCI Letters of Credit expired and were fully paid Fitch Inc. and Moody’s Investors Service, Inc., and no default has occurred by us on February 14, 2014, and the applicable interest rate ranged from 4.5% or is continuing under the indenture governing the Notes due 2020, certain to 5.45%. of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the ability of certain subsidiaries LGI Line of Credit In December 2012, in connection with its investment in GeoPark Colombia, to pay dividends, asset sales and certain transactions with affiliates will LGI granted as a credit line to Winchester (now GeoPark Colombia S.A.S.), or no longer be applicable. the LGI Line of Credit, of up to US$12.0 million, to be used for the acquisition, development and operation of oil and gas assets in Colombia. The applicable Our notes due 2020 contain limitations on the amount of indebtedness we interest rate is 8.00% per annum and any accrued interest is payable on a can incur. At current oil & gas prices, absent certain customary exceptions, we quarterly basis. do not anticipate achieving an EBITDA (as defined in the indenture governing our notes due 2020) during fiscal year 2015 that would be sufficient enough As of December 31, 2013, the outstanding amount of US$8.6 million relates to allow us to incur additional indebtedness, other than certain categories to a loan granted by LGI as part of its funding commitment in connection and small baskets of permitted debt, as specified in the indenture. with our Colombian acquisition. This loan was cancelled during 2014. As Events of default Events of default under the indenture governing the Notes due 2020 include: of Credit was US$16.6 million. This corresponds to a loan granted by LGI to GeoPark Chile S.A. for financing Chilean operations in our Tierra del Fuego the nonpayment of principal when due; default in the payment of interest, blocks for up to US$19 million. The maturity of this loan is July 2020 and the of December 31, 2014, the aggregate outstanding amount under the LGI Line which continues for a period of 30 days; failure to make an offer to purchase applicable interest rate is 8% per annum. and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indenture governing the See “-Item 4. Information on the Company-B. Business Overview-Significant Notes due 2020; the notes, or the security documents in relation thereto Agreements-Agreements with LGI.” that continues for a period of 60 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 cross-acceleration default following a judgment Rio das Contas Credit Facility We financed our Rio das Contas acquisition in part through our Brazilian for US$15.0 million or more; bankruptcy and insolvency events; invalidity or subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas denial or disaffirmation of a guarantee of the notes; and failure to maintain Credit Facility”) with Itaú BBA International plc, which is secured by the a perfected security interest in any collateral having a fair market value benefits GeoPark receives under the Purchase and Sale Agreement for Natural in excess of US$15.0 million, among others. The occurrence of an event of Gas with Petrobras. The facility matures five years from March 28, 2014, which default would permit or require the principal of and accrued interest on the Notes due 2020 to become or to be declared due and payable. was the date of disbursement and bears interest at a variable interest rate equal to the six-month LIBOR + 3.9%. The facility agreement includes customary events of default, and subject our Brazilian subsidiary to customary BCI Mortgage Loan In October 2007, in connection with our acquisition of a facility to establish an covenants, including the requirement that it maintain a ratio of net debt to EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. The credit operational base in the Fell Block, we executed a mortgage loan granted by facility also limits the borrower’s ability to pay dividends if the ratio of net the Banco de Crédito e Inversiones, or BCI, a Chilean private bank, which we debt to EBITDA is greater than 2.5x. We have the option to prepay the facility refer to as the BCI Mortgage Loan. The loan was granted in Chilean pesos and in whole or in part, at any time, subject to a pre-payment fee to be is repayable over a period of eight years. The interest rate under this loan is determined under the contract. fixed at 6.6%. As of December 31, 2014, the aggregate outstanding amount under the BCI Mortgage Loan was US$0.1 million. In March 2015, we reached an agreement to: (i) extend the principal payments that were due in 2015 (amounting to approximately US$15 million), BCI Letter of Credit During the last quarter of 2011, we obtained five short-term letters of credit 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 from BCI, or, collectively, the BCI Letters of Credit, to commence operations in the six-month LIBOR + 4.0%. our Tierra del Fuego blocks. Each of the BCI Letters of Credit contains a 150 GeoPark 20F C. Research and development, patents and licenses, etc. See “-Item 4. Information on the Company--B. Business Overview” and “-Item the outstanding long-term borrowing affected by variable rates amounted to $68.5 million representing 19% of total long-term borrowings, which was 4. Information on the Company-B. Business Overview-Title to Properties.” composed by the loan from Itaú International BBA plc that has a floating D. Trend information For a discussion of Trend information, see “-A. Operating Results-Factors affecting our results of operations.” E. Off-balance sheet arrangements We did not have any off-balance sheet arrangements as of December 31, 2013 or as of December 31, 2014. F. Tabular disclosure of contractual obligations In accordance with the terms of our concessions, we are required to make interest rate based on LIBOR (See Note 3: “Interest rate risk” to our audited financial statements included in this Annual Report). Furthermore, in March 2015, we reached an agreement to extend the principal payments that were due in 2015 and to increase the variable interest rate related to Itaú International BBA plc. See “Item 5. Operating and Financial Review and Prospects” -B. Liquidity and Capital Resources Indebtedness-Rio das Contas Credit Facility.” (2) Reflects the future aggregate minimum lease payments under non-cancellable operating lease agreements. royalty payments (1) in connection with crude oil and gas production in (3) Includes capital commitments in Isla Norte and Campanario Blocks in Argentina, to the Provinces of Santa Cruz and Mendoza, equivalent to 12% Chile, nine concessions in Brazil, two non-operated blocks in Argentina on estimated value at well head, (2) in connection with crude oil and gas and the Llanos 62, VIM3, CPO-4 and Llanos 17 Blocks in Colombia, which are production in Chile, to the Chilean government, equivalent to approximately our only remaining material commitments. See “-Item 4. Information on 5% of crude oil production and 3% of gas production, and (3) in connection the Company-B. Business overview-Our operations” and Note 31(b) to our with crude oil production in Colombia, to the Colombian government, audited financial statements included in this Annual Report. equivalent to 8%. The table below sets forth our committed cash payment obligations as of December 31, 2014. G. Safe harbor See “Forward-Looking Statements.” Less than One to Three to More than Total one year three years five years five years (in thousands of US$) 513,027 41,032 80,007 69,488 322,500 88,489 37,926 33,949 16,109 505 Debt obligations(1) Operating lease obligations(2) Pending investment commitments(3) 69,844 Asset retirement 20,064 27,580 22,200 - obligations 33,286 - 10,687 - 22,599 Total contractual obligations 704,646 99,022 152,233 107,797 345,604 (1) Refers to principal and interest undiscounted cash flows. Interest payment breakdown included in Debt Obligations is as follows (i) less than one year: $25.4 million; one to three years: $48.7 million; three to five years: $46.0 million and more than five years: $22.5 million. At December 31, 2014 GeoPark 20F 151 ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES A. Directors and senior management Board of directors The board of directors of GeoPark is composed of seven members. At every annual general meeting one third of the Directors shall 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 shall 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 term for the current directors expires on the date of our next annual shareholders’ meeting, to be held in 2015. The current members of the board of directors were appointed at the Company’s Annual General Meeting held on September 11, 2014. The table below sets forth certain information concerning our current board of directors. 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 66 59 64 45 64 66 55 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. 152 GeoPark 20F Gerald E. O’Shaughnessy has been our Chairman and a member of our board of directors since he co-founded the company in 2002. Following his Carlos Gulisano has been a member of our board of directors since June 2010. Dr. Gulisano holds a bachelor’s degree in geology, a post-graduate graduation from the University of Notre Dame with degrees in government degree in petroleum engineering and a PhD in geology from the University (1970) and law (1973), Mr. O’Shaughnessy was engaged in the practice of Buenos Aires and has authored or co-authored over 40 technical papers. of law in Minnesota. Mr. O’Shaughnessy has been active in the oil and gas He is a former adjunct professor at the Universidad del Sur, a former thesis business over his entire business career, starting in 1976 with Lario Oil and director at the University of La Plata, and a former scholarship director at Gas Company, where he served as Senior Vice President and General Counsel. CONICET, the national technology research council, in Argentina. Dr. Gulisano He later formed the Globe Resources Group, a private venture firm whose is a respected leader in the fields of petroleum geology and geophysics in subsidiaries provided seismic acquisition and processing, well rehabilitation South America and has over 30 years of successful exploration, development services, sophisticated logistical operations and submersible pump and management experience in the oil and gas industry. In addition to works for Lukoil and other companies active in Russia during the 1990s. serving as an advisor to GeoPark since 2002 and as Managing Director from Mr. O’Shaughnessy is also founder and owner of BOE Midstream, LLC, which February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera owns and operates the Bakken Oil Express, the largest crude by rail terminal Argentina San Jorge S.A. and Chevron San Jorge S.A. and has led teams in North Dakota, serving oil producers and marketing companies active credited with significant oil and gas discoveries, including those in the Trapial in the Bakken Shale Oil play. Over the past 25 years, Mr. O’Shaughnessy has field in Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador, also founded and operated companies engaged in banking, wealth Colombia, Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also management products and services, investment desktop software, computer an independent consultant on oil and gas exploration and production. 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 Juan Cristóbal Pavez has been a member of our board of directors since August 2008. He holds a degree in commercial engineering from the Governor of Kansas, the I.A. O’Shaughnessy Family Foundation, the Wichita Pontifical Catholic University of Chile and a MBA from the Massachusetts Collegiate School, the Institute for Humane Studies, The East West Institute Institute of Technology. He has worked as a research analyst at Grupo and The Bill of Rights Institute. Mr. O’Shaughnessy is a member of the CB and later as a portfolio analyst at Moneda Asset Management. In 1998, Intercontinental Chapter of Young Presidents Organization and World he joined Santana, an investment company, as Chief Executive Officer. At Presidents’ Organization. James F. 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 Santana 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 extensive experience in all phases of the upstream oil and gas business, with Executive Officer at Centinela, a company with a diversified global portfolio a strong background in the acquisition, implementation and management of investments, with a special focus in the energy industry, through the of international joint ventures in North America, South America, Asia, Europe development of wind parks and run-of-the-river hydropower plants. 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 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 and tectonic studies. In 1978, Mr. Park joined Basic Resources International of several companies, including Quintec, Enaex, CTI and Frimetal. 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 has lived in Argentina and Chile since 2002. GeoPark 20F 153 Peter 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 Pedro 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 in West Africa. Returning to the UK in 1976 to study for his Master’s degree 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance and legal in Petroleum Engineering at Imperial College, London following which matters. Mr. Aylwin holds a degree in law from the Universidad de Chile he joined Mobil North Sea. He moved to Unocal Corporation in 1979 where and an LLM from the University of Notre Dame. Mr. Aylwin has extensive he held increasingly senior positions, including as Managing Director of experience in the natural resources sector. Mr. Aylwin is also a partner at the Unocal UK in Aberdeen, Scotland, and where he developed extensive law firm of Aylwin Abogados in Santiago, Chile, where he represented mining, experience in offshore production and drilling operations. In 1994, Mr. Ryalls chemical and oil and gas companies in numerous transactions. From 2006 represented Unocal Corporation in the Azerbaijan International Operating until 2011, he served as Lead Manager and General Counsel at BHP Billiton, Company as Vice President of Operations and was responsible for production, Base Metals, where he was in charge of legal and corporate governance drilling, reservoir engineering and logistics. In 1998, Mr. Ryalls became matters on BHP Billiton’s projects, operations and natural resource assets in General Manager for Unocal in Argentina. He also served as Vice President South America, North America, Asia, Africa and Australia. Mr. Aylwin is also of Unocal’s Gulf of Mexico onshore oil and gas business and as Vice President a member of the board of directors of Egeda Chile. 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. 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, 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. He also served on the Board of Governors of the Congressional Country Club in Bethesda, Maryland. Since 2013, Mr. Bedingfield has also served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). 154 GeoPark 20F 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. Name James F. Park Andrés Ocampo Position Chief Executive Officer and Director Chief Financial Officer Pedro Aylwin Chiorrini Director, Director of Legal and Governance, and Corporate Secretary Augusto Zubillaga Alberto Matamoros Marcela Vaca Dimas Coelho Jose Díaz Carlos Murut Salvador Minniti Horacio Fontana Ruben Marconi Agustina Wisky Guillermo Portnoi Pablo Ducci Director for Argentina and Director of Operations Director for Chile Director for Colombia Director for Brazil Director for Peru Director of Development Director of Exploration Director of Drilling Director of Health, Safety & Environment Director of People Director of Administration and Finance Director of Capital Markets Age At the Company since 59 37 55 45 42 46 58 60 58 60 57 70 38 40 35 2002 2010 2003 2006 2014 2012 2013 2013 2006 2007 2008 2008 2002 2006 2012 Biographical information of the members of our executive officers is set forth below. Unless otherwise indicated, the current business addresses for Augusto Zubillaga has served as our Director of Operations since January 2012 and Director for Argentina since February 2015. He previously served our executive officers is Nuestra Señora de los Ángeles 179, Las Condes, as our Production Director. He is a petroleum engineer with 19 years of Santiago, Chile. Andrés Ocampo has served as our Chief Financial Officer since November 2013. He previously served as our Director of Growth and Capital (from experience in production, engineering, well completions, corrosion control, reservoir management and field development. He has a degree in petroleum engineering from the Instituto Tecnológico de Buenos Aires. Prior to joining our company, Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. January 2011 through October 2013), and has been with our company since and Chevron San Jorge S.A. At Chevron San Jorge S.A., he led multi- July 2010. Mr. Ocampo graduated with a degree in Economics from the disciplinary teams focused on improving production, costs and safety, and Universidad Católica Argentina. He has more than 12 years of experience in business and finance. Before joining our company, Mr. Ocampo worked at was the leader of the Asset Development Team, which was responsible for creating the field development plan and estimating and auditing the oil Citigroup and served as Vice President Oil & Gas and Soft Commodities at and gas reserves of the Trapial field in Argentina. Mr. Zubillaga was also Crédit Agricole Corporate & Investment Bank. part of a Chevron San Jorge S.A. team that was responsible for identifying business opportunities and working with the head office on the establishment of best business practices. He has authored several industry papers, including papers on electrical submersible pump optimization, corrosion control, water handling and intelligent production systems. GeoPark 20F 155 Alberto Matamoros has been our Director for Chile since January 2015. He is an industrial engineer and MBA, with more than 17 years of experience Bahia, Brazil, a Ph.D. in geology (Numerical Basin Modelling) from Cornell University and an MBA in general administration from the Federal University in the Oil & Gas industry. He started his career in the Argentinian oil company of Rio de Janeiro, Brazil. ASTRA, as a Production Engineer of La Ventana-Vizcacheras Block in the province of Mendoza (1997-2000). He then joined Chevron, where he worked as a Production Engineer in El Trapial Block in the province of Neuquén for Carlos Murut has been our Director of Development since January 2012. He previously served as our Development Manager. Mr. Murut holds a master’s three years. Later, he became a Field Engineering Manager, also for three degree in petroleum geology from the University of Buenos Aires where he years, in Buenos Aires, and then moved to Kern, California, to lead the also undertook postgraduate studies in reservoir engineering, specializing in production team. His experience in Chevron enabled him to manage different field exploitation. He also completed a Business Management Development technical and administrative teams, designing and executing working plans Program at Austral University. Mr. Murut has over 30 years of experience focused in the optimization of resources. In 2014, he joined GeoPark to be working for international and major oil companies, including YPF S.A., part of the Corporate Operation team before being selected as the new Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. Country Manager of GeoPark in Chile. Matamoros holds a degree in Industrial Engineering from the Universidad Nacional del Sur and an MBA in IAE, from the Business School of Universidad Austral of Buenos Aires, Argentina. Salvador Minniti has been our Director of Exploration since January 2012. He previously served as our Exploration Manager. He holds a bachelor degree in geology from National University of La Plata and has a graduate degree Marcela Vaca has been our Director for Colombia since August 2012. Ms. Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá, from the Argentine Oil and Gas Institute in oil geology. Mr. Minniti has over 30 years of experience in oil exploration and has worked with YPF S.A., Petrolera Colombia, a Master’s Degree in commercial law from the same university and Argentina San Jorge S.A. and Chevron Argentina. an LLM from Georgetown University. She has served in the legal departments of a number of companies in Colombia, including Empresa Colombiana de Carbon Ltda (which later merged with INGEOMINAS), and from 2000 to 2003, Jose Díaz has been our Director for Peru since September 2014. He previously served as our Director of Operations (from January 2013 through September she served as Legal and Administrative Manager at GHK Company Colombia. 2014). Mr. Díaz holds a degree in petroleum engineering from Cuyo National Prior to joining our company in 2012, Ms. Vaca served for nine years as University, Argentina, has taken executive business classes at IAE Business General Manager of the Hupecol Group where she was responsible for School, and pursued graduate studies in oil and gas law and project supervising all areas of the company as well as managing relationships with management at University of Buenos Aires School of Law and Alta Dirección Ecopetrol, ANH, the Colombian Ministry of Mines and Energy, the Colombian Escuela de Negocios, respectively. He has over 30 years of experience in Ministry of Environment and other governmental agencies. At the Hupecol upstream operations as a petroleum engineer, including more than 15 years Group, Ms. Vaca was also involved in the structuring of the Hupecol Group’s in managerial positions. This experience includes positions at international asset development and sales strategy. and major oil companies, including OEA S.A., Chevron San Jorge S.A., ChevronTexaco and Petrolera El Trebol S.A. Dimas Coelho has served as our Director for Brazil since February 2013. He is a geologist and geophysicist with over 30 years of experience in hydrocarbons exploration. From 1981 to 2011, Dr. Coelho served Petrobras’ Horacio Fontana has been our Corporate Drilling Manager since March 2012. He previously served as our Engineer Manager. He holds a degree in civil E&P and R&D areas in innumerous capacities, including as a Petroleum engineering from Rosario National University and is also a graduate from Exploration Manager in Business Unit (from 2001 to 2004) and Corporate the Argentine Oil and Gas Institute, National University of Buenos Aires, with areas (from 2006 to 2010), in which roles he was responsible for the planning, a specialty in oilfield exploitation and an extensive background in drilling management and execution of exploration programs in the exploration operations. He has recently taken part in a Management Development and production blocks in Brazil’s Campos and Santos Basin. Later (2011) as Program at IAE Business School of Austral University. Mr. Fontana has over a Joint Venture Project Manager he was responsible for the coordination 25 years of drilling experience in major Argentine companies such as of Petrobras’s functional areas to support Petrobras’s work programs in the YPF S.A., Petrolera Argentina San Jorge and Chevron. Santos Basin. In 2012, he served as Executive Vice President of Exploration at Panoro Energy do Brasil, where he oversaw the exploration functional workflow for Panoro Energy ASA’s exploration assets in Brazil. Dr. Dimas holds Ruben Marconi has been our Director of Health, Safety and Environment since March 2012. He previously served as our Drilling Director. He holds a degree in geology from the Federal University of Rio de Janeiro, Brazil, an a degree in mechanical engineering from Rosario University and was a YPF MSc degree in geophysics (seismic processing) from the Federal University of scholar at the University of Buenos Aires where he graduated in oil engineering with a concentration in exploitation. Mr. Marconi has over 40 156 GeoPark 20F years of field onshore, offshore drilling, completion and safety experience US$500,000. The payment of a bonus to Mr. O’Shaughnessy or Mr. Park is at with YPF, Petrolera Argentina San Jorge, ChevronTexaco, Chevron Mid our discretion. They each also received equity awards described below under Continent Business Unit and Chevron Argentina. “Equity Incentive Compensation.” Our agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that restrict them, for a period of 12 months Agustina Wisky has worked with our Company since it was founded in November 2002, and has served as our Director of People since 2012. following termination of employment, from soliciting senior employees of our company and, for a period of six months following the termination of Mrs. Wisky is a public accountant, and also holds a degree in human employments, from being involved in any competing undertaking. Pedro resources from the Universidad Austral-IAE. She has 14 years of experience Aylwin, who was appointed as an executive director in July 2013, has a service in the oil industry. Before joining our company, Mrs. Wisky worked at AES contract with our company that provides for him to act as Director of Legal Gener and PricewaterhouseCoopers. and Governance, and as such has decided to forego his director fees, but he Guillermo Portnoi has been our Director of Administration and Finance since 2011 and has worked for us since June 2006. Mr. Portnoi is a public The following chart summarizes payments made to our executive directors accountant and holds an MBA from Universidad Austral-IAE. He has more for the year ended December 31, 2014: received consultancy fees of approximately US$568,000. than 10 years of experience in the oil industry. Before joining our company, Mr. Portnoi worked at Pluspetrol, Río Alto and PricewaterhouseCoopers, where he counted several major oil companies as his clients. Pablo Ducci has served as our Director of Capital Markets since 2012. Mr. Ducci holds a bachelor’s degree in science and economics from Pontifical Catholic University of Chile and a master’s degree in business administration Executive director Gerald E. O’Shaughnessy James F. Park Executive directors’ fees US$250,000 US$500,000 Cash payment Bonus US$150,000 US$650,000 from Duke University. From 2004 to 2009, Mr. Ducci worked as a Corporate Bonus payments above were approved by the Remuneration Committee Finance Analyst and Corporate Finance Associate with Celfin Capital. In 2010, in May and August 2014 and reflect awards for previous years performance. he worked as an Associate for Anka Funds, and from 2011 to 2012, he served As part of Company's cost reduction efforts, no bonus has been paid as Vice President of Development for Falabella Retail. for 2014 performance, and executive fees for 2015 have been voluntarily B. Compensation reduced by 20%. Executive compensation For the year ended December 31, 2014, the aggregate compensation Non-executive directors’ contracts During the first half of 2014, our non-executive directors were paid an annual fee of GBP35,000, payable quarterly in arrears. At our option, the fee accrued or paid to the members of our board of directors (including our paid to our non-executive directors can be paid through the issuance executive directors) for services in all capacities was approximately US$5.4 million. Gerald E. O’Shaughnessy, James F. Park and Pedro Aylwin are of new common shares and/or cash. In addition, the Chairmen of the Audit Committee, the Remuneration Committee and the Nomination Committee our executive directors. For the year ended December 31, 2014, the were paid an additional annual fee of GBP5,750 each. The termination of aggregate compensation accrued or paid to the members of our senior the employment relationship does not entitle non-executive directors to any management (excluding our executive directors) for services in all capacities financial compensation. From the second half of 2014, an increase in the was approximately US$9.1 million. Executive directors’ contracts It is our policy that executive directors have contracts of an indefinite term compensation program for the services of the non-executive Directors was approved. The current annual fees correspond to US$80,000 to be settled in cash and US$100,000 to be settled in stock, paid quarterly in equal installments. In the event that a non-executive Director serves as Chairman providing for a maximum of one-year’s notice in writing of termination of any Board Committees, an additional annual fee of US$20,000 applies. at any time. A Director who serves as a member of any Board Committees receives an annual fee of US$10,000. Total payment due shall be calculated on an Gerald E. O’Shaughnessy has a service contract with our company that aggregate basis for Directors serving in more than one Committee. The provides for him to act as Executive Chairman at an annual salary of Chairman fee is not be added to the member’s fee while serving for the same US$250,000. James F. Park has a service contract with our company that Committee. Payments of Chairmen and Committee members’ fees are be provides for him to act as Chief Executive Officer at an annual salary of made quarterly in arrears and settled in cash only. GeoPark 20F 157 The following chart summarizes payments made to our non-executive shares for zero or nominal consideration, subject to the achievement of directors for the year ended December 31, 2014. performance conditions and other vesting terms. The maximum number of Cash payment Share payment(1) Fees paid in common shares available for issuance under the Stock Awards Plan is 12% of the issued share capital of the Company. Non-executive directors’ fees directors’ fees (in number of and Exchange Commission (the “SEC”) for shares to be issued under the Non-executive Non-executive common shares On December 17, 2014, we registered 3,435,600 shares with the U.S. Securities in US$ common shares) Stock Awards Plan. The following table sets forth the common share awards granted to our executive directors, management and key employees under the Stock Awards Plan commencing in 2008 through March 2015, that remained outstanding as of such latter date. 7,003 7,003 5,250 director Juan Cristóbal Pavez(2) Peter Ryalls(3) Carlos Gulisano(4) Steven J. Quamme(5) in GBP 11,625 8,750 20,375 11,625 55,000 57,500 55,000 55,000 7,003 Number of underlying (1) 2,301 shares of total shares (which amount to 26,259) were issued during 2014. common shares outstanding 873,409(1) 817,600 (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 478,000 720,000(2) 400,500(3) 417,000(4) 500,000 until resignation in 2015. Grant date Vesting Expiration date date 12/15/2008 12/15/2012 12/15/2018 12/15/2010 12/15/2014 12/15/2020 12/15/2011 12/15/2015 12/15/2021 11/23/2012 11/23/2015 11/23/2016 12/15/2012 12/15/2016 12/15/2022 6/30/2013 12/31/2015 12/31/2019 12/31/2014 12/31/2017 12/31/2022 Pension and retirement benefits We do not maintain any defined benefit pension plans or any other (1) Dr. Carlos Gulisano holds 100,000 shares of such awards. (2) James F. Park received 450,000 shares of such awards, and Gerald E. O’Shaughnessy received 270,000 shares of such awards. retirement programs for our employees or directors. (3) This amount includes 50,000 common share awards that vested on Equity Incentive Compensation Management and Employee Plans In November 2007, our shareholders voted to authorize the board of directors to use up to a maximum of 12% of our issued share capital for the purposes October 31, 2014. (4) Vesting of these common share awards is subject to the achievement of certain minimum financial and operational targets during a performance period that runs through 2015. Our executive directors, senior management and key employees who have of granting equity awards to our employees and other service providers. received option awards or common share awards under the Stock Awards The shareholders also authorized the board of directors to adopt programs Plan authorize the Company to deposit any common shares they have for this purpose and to determine specific conditions and broadly defined received under this plan in our Employee Benefit Trust, or EBT. The EBT is held guidelines for such programs. Pursuant to this authorization, we established to facilitate holdings and dispositions of those common shares by the the Stock Awards Plan and the Value Creation Plan. participants thereof. Under the terms of the EBT, each participant is entitled to receive any dividends we may pay which correspond to their common Stock Awards Plan In November 2008, the board of directors adopted the Stock Awards Plan. The shares held by the trust, according to instructions sent by the Company to the trust administrator. The trust provides that Mr. James F. Park is entitled to purpose of the Stock Awards Plan is to align the interests of our management, vote all the common shares held in the trust. 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 Value Creation Plan In July 2013, our remuneration committee established the Value Creation number of common shares of the Company at an exercise price equal to the Plan, or VCP, to give our executive officers and key management members par value of the common shares subject to such an option. A performance the opportunity to share in a percentage of the value created for shareholders share confers a conditional right to acquire a specified number of common in excess of a pre-determined share price target at the end of a performance 158 GeoPark 20F period. Under the VCP, if as of December 31, 2015, our share price (defined Program. The repurchased shares will be used to offset, in part, any expected as the average trading price of our common shares on the NYSE for the dilution effects resulting from the Company’s equity incentive compensation month of December 2015) exceeds US$13.66, VCP participants will receive plans, including grants under the Stock Awards Plan and the Non-Executive awards with an aggregate value equal to 10% of the excess above the market Director Plan. As of March 27, 2015 US$1.4 million of shares has been purchased capitalization threshold generated by this share price (assuming that the under the Share Repurchase Program. On April 13, 2015, our board of directors share capital of the Company has remained at the same level as applicable approved the resumption of the Share Repurchase Program commencing at the time of establishment of the VCP: 43,495,585 shares). The awards on April 14, 2015 and expiring at the close of business on May 20, 2015. will vest and be paid in common shares 50% on December 31, 2015, and the remaining 50% on December 31, 2016. Notwithstanding the foregoing, C. Board practices the total number of common shares granted pursuant to this plan shall not exceed 5% of the issued share capital of the Company. Additionally, the share price (and number of common shares outstanding) used to calculate if the Overview Our board of directors is responsible for establishing our strategic goals, market capitalization threshold has been met is subject to adjustment for any ensuring that the necessary resources are in place to achieve these goals stock splits. Based on the Company’s performance to date, we currently do and reviewing our management and financial performance. Our board of not expect the performance conditions of the VCP awards to be achieved. directors directs and monitors the company in accordance with a framework Non-Executive Director Plan In August 2014, our board of directors adopted the Non-Executive of controls, which enable risks to be assessed and managed through clear procedures, lines of responsibility and delegated authority. Our board of directors also has responsibility for establishing our core values and Director Plan in order to grant shares to Non-Executive directors as part of standards of business conduct and for ensuring that these, together with our their compensation program for serving as directors. The purpose of the obligations to our shareholders, are understood throughout the company. Non-Executive Director Plan is to grant shares in connection with the quarterly payments of the Non-Executive Directors’ fees which are settled in stock, according to the Board Resolution dated May 20, 2014. Under the Board composition Our bye-laws and board resolutions provide that the board of directors Non-Executive Director Plan, the remuneration committee may award consist of a minimum of three and a maximum of nine members. All of our common shares, restricted share units and other share-based awards that directors were elected at our annual shareholders’ meeting held on may be denominated or payable in common shares or factors that influence September 11, 2014, with the exception of Mr. Robert Bedingfield who was the value of common shares. The maximum number of common shares appointed by the Board of Directors on March 19, 2015, to fill the vacancy available for issuance under the Non-Executive Director Plan is 180,000 created by Mr. Steven Quamme’s resignation. Their term expires on the common shares. The remuneration committee has, as of March 31, 2015, date of our next annual shareholders’ meeting, to be held in 2015. The board awarded an aggregate amount of 37,172 common shares, which were of directors meets at least on a quarterly basis. immediately vested upon grant, under the Non-Executive Director Plan. Potential dilution resulting from Equity Incentive Compensation Plans The percentage of total share capital that could be awarded to our directors, Committees of our board of directors Our board of directors has established an Audit Committee, a Compensation Committee, a Nomination Committee, and a Technical Committee. The management and key employees under the Stock Awards Plan and the composition and responsibilities of each committee are described below. VCP and the Non-Executive Director Plan described above would represent Members serve on the Audit Committee for a period of three years. For approximately 12% of our issued common shares. However, as of the date of the Compensation and Nomination Committees, members serve for a period this annual report, we have awarded approximately 5.95% of our current of one year. For the Technical Committee and Disclosures Committee, total issued share capital. This percentage does not include shares that may members serve on these committees until their resignation or until otherwise be issued under the VCP, and we currently do not expect to issue any shares determined by our board of directors. In the future, our board of directors under the VCP. may establish other committees to assist with its responsibilities. Share Repurchase Program In December 2014, our board of directors approved a Share Repurchase Audit Committee The Audit Committee is composed of three directors: Mr. Peter Ryalls, Program of up to US$10 million of our common shares, par value US$0.001 per Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield (who currently serves as share. The Share Repurchase Program began on December 19, 2014 and Chairman of the committee). We have determined that Mr. Peter Ryalls expired at the close of business on March 27, 2015. We engaged BTG Pactual and Mr. Juan Cristóbal Pavez and Robert Bedingfield are independent, as such US Capital LLC to act as the broker in connection with the Share Repurchase term is defined under SEC rules applicable to foreign private issuers. GeoPark 20F 159 The Audit Committee’s responsibilities include: (a) approving our financial and Compensation Committee in consultation with the chairman of each statements; (b) reviewing financial statements and formal announcements committee, and with respect to the appointment of any director or executive relating to our performance; (c) assessing the independence, objectivity and officer or other officer other than the position of the Chairman and Chief effectiveness of our external auditors; (d) making recommendations for the Executive Officer and (d) succession planning for directors and senior appointment, re-appointment and removal of our external auditors and executives. approving their remuneration and terms of engagement; (e) implementing and monitoring policy on the engagement of external auditors supplying non-audit services to us; (f) obtaining, at our expense, outside legal or other Technical Committee The Technical Committee is composed of three directors along with the professional advice on any matters within its terms of reference and securing Chief Operating Officer. The members of the Technical Committee are the attendance at its meetings of outsiders with relevant experience and Mr. Peter Ryalls (who serves as Chairman of the committee), Mr. Carlos expertise if it considers it necessary; and (g) reviewing our arrangements for Gulisano, Mr. James Park and Mr. Augusto Zubillaga. our employees to raise concerns about possible wrongdoing in financial reporting or other matters and the procedures for handling such allegations, The Technical Committee’s responsibilities include: (a) overseeing the and ensuring that these arrangements allow proportionate and independent technical studies and evaluations of the Company’s properties and proposals investigation of such matters and appropriate follow-up action. to acquire new properties and/or relinquish existing ones as well as reviewing Compensation Committee The Compensation Committee is composed of three directors. The current environmental programs and their effectiveness and the Company’s health and safety program and its effectiveness; and (c) providing a forum for ideas members of the compensation committee are Mr. Juan Cristóbal Pavez and solutions for the key technical people within the Company. project plans; (b) reviewing the Annual Reserve Report, the Company’s (who serves as Chairman of the committee), and Mr. Peter Ryalls. Currently there is a vacancy created by the resignation of Mr. Steve J. Quamme Liability insurance effective March 19, 2015. We maintain liability insurance coverage for all of our directors and officers, The Compensation Committee meets at least twice a year, and its specific the level of which is reviewed annually. responsibilities include: (a) determining, in conjunction with the board of directors, the remuneration policy for the Chief Executive Officer, the Chairman, our executive directors and other members of executive D. Employees As of December 31, 2014, we had approximately 456 employees, of which management; (b) reviewing the performance of our executive directors and 197 were located in Chile, 133 were located in Colombia, 100 were located in members of executive management; and (c) reviewing all incentive Argentina, 12 were located in Brazil and 14 in Peru. This represented an compensation plans, equity-based plans, and all modifications to such plans increase of 13% from December 31, 2013, an increase largely attributable to as well as administering and granting awards under all such plans and the growth of our Colombian operations and new projects in Peru, mainly approving plan payouts; and (d) reviewing and making recommendations to the Board with respect to the adoption or modification of executive related to the Morona Block. officer and director share ownership guidelines and monitor compliance The following table sets forth a breakdown of our employees by geographic with any adopted share ownership guidelines. segment for the periods indicated. Nomination Committee The Nomination Committee is composed of three directors. The members of the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. Carlos Chile Gulisano (who serves as Chairman of the committee) and Mr. Pedro Aylwin. Colombia Argentina The Nomination Committee meets at least twice a year and its responsibilities Peru include: (a) reviewing the structure, size and composition of the board of directors and making recommendations to the board of directors in respect Brazil Total of any required changes; (b) identifying, nominating and submitting for Year ended December 31, 2014 197 133 100 14 12 456 2013 193 109 98 - 4 2012 163 98 92 - - 404 353 approval by the board of directors candidates to fill vacancies on the board From time to time, we also utilize the services of independent contractors to of directors as and when they arise; (c) making recommendations to the perform various field and other services as needed. As of December 31, 2014, board of directors with respect to the membership of the Audit Committee 14 of our employees were represented by labor unions or covered by 160 GeoPark 20F collective bargaining agreements. We believe that relations with our “-Item 6. Directors, Senior Management and Employees-B. Compensation- employees are satisfactory. Employee Benefit Trust.” Although Mr. Park has voting rights with respect to all the common shares held in the trust, Mr. Park disclaims beneficial E. Share ownership As of the date of this annual report, members of our board of directors and ownership over those common shares. (3) Held through Socoservin Overseas Ltd, which is controlled by Juan our senior management held as a group 19,028,992 of our common shares Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez and 33.03% of our outstanding share capital. include 18,863 common shares held by him personally. The following table shows the share ownership of each member of our board of directors and senior management as of the date of this annual report. ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 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 7,601,276 7,441,269 2,896,667 125,832 153,031 54,988 15,000 * * * * * * * * * * * * * Percentage of outstanding A. Major shareholders The following table presents the beneficial ownership of our common shares common shares as of April 8, 2015. 13.20 12.91 5.03 0.20 0.23 0.08 0.03 * * * * * * * * * * * * * Shareholder Steven J. Quamme(1) Gerald E. O’Shaughnessy(2) James F. Park(3) IFC Equity Investments(4) Juan Cristóbal Pavez(5) Moneda A.F.I.(6) Other shareholders Total Common shares 9,708,698 7,601,276 7,441,269 3,456,594 2,896,667 2,685,421 23,813,820 57,603,745 Percentage of outstanding common shares 16.85 13.20 12.91 6.00 5.03 4.66 41.34 100.0% (1) Held through certain private investment funds managed and controlled by Cartica Management, LLC. The common shares reflected as being held by Mr. Quamme include 17,736 common shares held by him personally. Mr. Steven Quamme, one of our principal shareholders is the Senior Managing Director of Cartica Management, LLC, and therefore may be deemed to have voting and investment power over the common shares of GeoPark held by Cartica Management, LLC. Sub-total senior management ownership of less than 1% Total 740,929 19,028,992 (2) Held directly and indirectly through GP Investments LLP, GPK Holdings 1.30 LLC and The Globe Resources Group Inc. 3,000,000 of these common shares 33.03 have been pledged pursuant to lending arrangements. (3) Held by Energy Holdings, LLC, which is controlled by James F. Park, a * Indicates ownership of less than 1% of outstanding common shares. member of our Board of Directors. The number of common shares held by (1) Held directly and indirectly through GP Investments LLP, GPK Holdings Mr. Park does not reflect the 588,664 common shares held as of December 31, LLC and The Globe Resources Group Inc., all of which are controlled by 2014 in the employee benefit trust described under “-Item 6. Directors, Mr. O’Shaughnessy. 3,000,000 of these common shares have been pledged Senior Management and Employees-B. Compensation-Employee Benefit pursuant to lending arrangements. Trust.” Although Mr. Park has voting rights with respect to all the common (2) Held by Energy Holdings, LLC, which is controlled by James F. Park, a shares held in the trust, Mr. Park disclaims beneficial ownership over member of our Board of Directors. 498,915 pf these shares have been those common shares. 498,915 of these common shares have been pledged pledged pursuant to lending agreements. The number of common shares pursuant to lending arrangements. held by Mr. Park does not reflect the 588,664 common shares held as of the (4) IFC Equity Investments voting decisions are made through a portfolio date of this annual report in the employee benefit trust described under management process which involves consultation from investment officers, GeoPark 20F 161 credit officers, managers and legal staff. party is subject to tag-along and drag-along rights, and the non-transferring (5) Held through Socoservin Overseas Ltd, which is controlled by Juan shareholder has the right to object to a sale to the third-party if it considers Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez such third-party to be not of a good reputation or one of our direct include 9,326 common shares held by him personally. competitors. We and LGI also agreed to vote our common shares or otherwise (6) Held through various funds managed by Moneda A.F.I. (Administradora cause GeoPark Chile or GeoPark TdF, as applicable, to declare dividends de Fondos de Inversión), an asset manager. only after allowing for retentions to meet anticipated future investments, costs and obligations. See “-Item 4. Information on the Company-B. Business Principal shareholders do not have any different or special voting rights in overview-Significant agreements-Agreements with LGI-LGI Chile comparison to any other common shareholder. Shareholders’ Agreements.” According to our transfer agent, as of March 31, 2015, we had 5 shareholders registered in the U.S. As of December 31, 2014, there were a total of 16 LGI Colombia Agreements On December 18, 2012, we, Agencia, GeoPark Colombia and LGI entered shareholders of record. Since some of the shares are held by nominees, the into the LGI Colombia Shareholders’ Agreement and a subscription share number of shareholders may not be representative of the number of agreement, pursuant to which LGI acquired a 20% interest in GeoPark beneficial owners. B. Related party transactions We have entered into the following transactions with related parties: Colombia. Further, on January 8, 2014, following an internal corporate reorganization of our Colombian operations, GeoPark Colombia Coöperatie U.A. and GeoPark Latin America entered into a new members’ agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out substantially similar rights and obligations to the LGI Colombia Shareholders’ LGI Chile Shareholders’ Agreements In 2010, we formed a strategic partnership with LGI to acquire and develop Agreement in respect of our oil and gas business in Colombia. We refer to the LGI Colombia Shareholders’ Agreement and the LGI Colombia Members’ jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired a Agreement collectively as the LGI Colombia Agreements. The LGI Colombia 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark Agreements provide that the board of GeoPark Colombia will consist of TdF, for a total consideration of US$148.0 million, plus additional equity four directors; as long as LGI holds at least 14% of GeoPark Colombia, LGI has funding of US$18.0 million through 2014. On May 20, 2011, in connection the right to elect one director and such director’s alternate, while the with LGI’s investment in GeoPark Chile, we and LGI entered into the LGI Chile remaining directors, and alternates, are elected by us. Additionally, the LGI Shareholders’ Agreements, setting forth our and LGI’s respective rights and Colombia Agreements require the consent of LGI or the LGI appointed obligations in connection with LGI’s investment in our Chilean oil and gas director for GeoPark Colombia to be able to take certain actions, including, business. Specifically, the LGI Chile Shareholders’ Agreements provide that among others: making any decision to terminate or permanently or the boards of each of GeoPark Chile and GeoPark TdF will consist of four indefinitely suspend operations in or surrender our blocks in Colombia (other directors; as long as LGI holds at least 5% of the voting shares of GeoPark than as required under the terms of the relevant concessions for such blocks); Chile or GeoPark TdF, as applicable, LGI has the right to elect one director and such director’s alternate, while the remaining directors, and alternates, are creating a security interest over our blocks in Colombia; approving of GeoPark Colombia’s annual budget and work programs and the mechanisms elected by us. Additionally, the agreements require the consent of LGI or its for funding any such budget or program; entering into any borrowings other appointed director in order for GeoPark Chile or GeoPark TdF, as applicable, than those provided in an approved budget or incurred in the ordinary to be able to take certain actions, including, among others: making any course of business to finance working capital needs; granting any guarantee decision to terminate or permanently or indefinitely suspend operations in or or indemnity to secure liabilities of parties other than those of our Colombian surrender our blocks in Chile (other than as required under the terms of the subsidiaries; changing the dividend, voting or other rights that would give relevant CEOP for such blocks); selling our blocks in Chile to our affiliates; preference to or discriminate against the shareholders of GeoPark Colombia; making any change to the dividend, voting or other rights that would give entering into certain related party transactions; and disposing of any preference to or discriminate against the shareholders of these companies; material assets other than those provided for in an approved budget and entering into certain related party transactions; and creating a security work program. The LGI Colombia Agreements also provide that: (i) if either interest over our blocks in Chile (other than in connection with a financing we or LGI decide to sell our respective shares in GeoPark Colombia, the that benefits our Chilean subsidiaries). The LGI Chile Shareholders’ transferring shareholder must make an offer to sell those shares to the other Agreements also provide that: (i) if LGI or either Agencia or GeoPark Chile shareholder before selling those shares to a third party; and (ii) any sale to a decides to sell its shares in GeoPark Chile or GeoPark TdF, as applicable, the third party is subject to tag-along and drag-along rights, and the non- transferring shareholder must make an offer to sell those shares to the other transferring shareholder has the right to object to a sale to the third-party if it shareholder before selling them to a third party; and (ii) any sale to a third considers such third-party to be not of a good reputation or one of our direct 162 GeoPark 20F competitors. We and LGI also agreed to vote our common shares or management of our activities; maintain certain forms of insurance coverage, otherwise cause GeoPark Colombia to declare dividends only after allowing including coverage for public liability and director’s and officer’s liability for retentions for approved work programs and budgets, capital adequacy reasonably acceptable to IFC, and in respect of certain of our operations; and tied surplus requirements of GeoPark Colombia, working capital not undertake certain prohibited activities; and ensure that no prohibited requirements, banking covenants associated with any loan entered into payments are made by us or on our or the Lead Investors’ behalf, in respect by GeoPark Colombia or our other Colombian subsidiaries and operational of our operations. requirements. See “-Item 4. Information on the Company-B. Business overview-Significant agreements-Agreements with LGI-LGI Colombia We also agreed to provide to IFC, within 30 days of the end of the first half Agreements.” LGI Stand-by Letters of Credit In 2011, in connection with LGI’s acquisition of a 20% equity interest in of the year, copies of our unaudited consolidated financial statements for the period (prepared under IFRS), a report on our capital expenditures for the period, a comprehensive report on the progress of the exploration, development and exploitation of our blocks in Latin America and a statement GeoPark Chile and a 14% equity interest in GeoPark TdF for US$148.0 million. of all related party transactions during the period, with a certification by a company officer that these were on an arm’s-length basis; within 90 days of LGI provided to GeoPark TdF standby letters of credit for an amount of the end of our fiscal year, copies of our audited consolidated financial US$31.6 million (corresponding to its pro rata share in GeoPark TdF) and for statements for the year (prepared under IFRS), a management letter from our an additional amount of US$52.3 million (or the additional amount), auditors in respect of our financial control procedures, accounting and resulting in an aggregate of US$84.0 million in standby letters of credit, or management information systems and any litigation, an annual monitoring the LGI Stand-by Letters of Credit, to partially secure the US$101.4 million report confirming compliance with national or local requirements and the performance bond required by the Chilean government to guarantee environmental and social requirements mandated by the agreement, a report GeoPark TdF’s obligations with respect to the first period’s minimum work indicating any payments in the year to any governmental authority in program under the Tierra del Fuego CEOPs. The remaining US$17.4 million connection with the documents governing our Chilean and Argentine blocks was provided by GeoPark. All costs and liabilities regarding the additional and certificates of insurance, with a certificate of our insurer confirming that amount shall be paid by GeoPark. GeoPark has already applied to the Ministry effectiveness of our policies and payment of all applicable premiums; within of Energy for an aggregate reduction of approximately US$35 million in the 45 days before each fiscal year begins, a proposed annual business plan and amount owed on the performance bond because minimum work obligations budget for the upcoming year; within 3 days after its occurrence, notification imposed by the terms of the bond have been met. of any incident that had or may reasonably be expected to have an adverse effect on the environment, health or safety; copies of notices, reports or other The LGI Stand-by Letters of Credit initially expired on March 31, 2013, and communications between us and our board of directors or shareholders; and, were renewed until May 18, 2016, and the applicable interest rate is 1.5%. As within five days of receipt thereof, copies of any reports, correspondence, of December 31, 2014, the aggregate outstanding amount attributable to documentation or notices from any third-party, governmental authority or GeoPark’s share under the LGI Stand-by Letters of Credit was US$50.3 million. IFC Subscription and Shareholders’ Agreement On February 7, 2006, in order to finance the exploration, development and exploitation of our blocks in Chile and Argentina and the acquisition of state-owned company that could reasonably be expected to materially impact our operations. Mr. O’Shaughnessy and Mr. Park have also agreed to procure that shareholders holding 51% of our common shares cause us to comply with the covenants above. additional exploration, development and exploitation blocks in Latin America, we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead Investors, Executive Directors’ Service Agreements We have entered into service contracts with certain of our executive directors. entered into an agreement, or the IFC Subscription and Shareholders’ See “-Item 6. Directors, Senior Management and Employees-B. Compensation- Agreement, pursuant to which IFC agreed to subscribe and pay for Executive compensation-Executive directors’ contracts.” 2,507,161 of our common shares, representing approximately 10.5% of our then-outstanding common shares, at an aggregate subscription price of For further information relating to our related party transactions and balances US$10.0 million (or approximately US$3.99 per common share). outstanding as of December 31, 2014, 2013 and 2012, please see Note 32 to We agreed, for so long as IFC is a shareholder in the company, among other things, to: ensure that our operations are in compliance with certain environmental and social guidelines; appoint and maintain a technically qualified individual to be responsible for the environmental and social our audited consolidated financial statements. C. Interests of Experts and Counsel Not applicable. GeoPark 20F 163 ITEM 8. FINANCIAL INFORMATION Dividends and dividend policy Holders of common shares will be entitled to receive dividends, if any, paid A. Consolidated statements and other financial information on the common shares. Financial statements See “-Item 18. Financial Statements,” which contains our audited financial We have never declared or paid any cash dividends on our common shares. We intend to retain all of our future earnings, if any, generated by our statements prepared in accordance with IFRS. operations for the development and growth of our business. Accordingly, we do not expect to pay cash dividends on our common shares in Legal proceedings From time to time, we may be subject to various lawsuits, claims and the foreseeable future. Because we are a holding company with no direct operations, we will only be able to pay dividends from our available proceedings that arise in the normal course of business, including cash on hand and any funds we receive from our subsidiaries. The terms employment, commercial, environmental, safety and health matters. of our indebtedness may restrict us from paying dividends, or restrict our For example, from time to time, we receive notice of environmental, health subsidiaries from paying dividends to us. and safety violations. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated Under the Bermuda Companies Act, we may not declare or pay a dividend financial position and results of operations. 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 As of the date of this Annual Report, in Brazil, GeoPark Brazil is a party to a realizable value of our assets would thereafter be less than our liabilities. We legal proceeding related to the entry into the concession agreement of do not presently have any reasonable grounds for believing that, if we were exploratory Block PN-T-597 that the ANP initially awarded to GeoPark Brazil in to declare or pay a dividend on our common shares outstanding, we would the 12th oil and gas bidding round held in November 2013. As a result of a thereafter be unable to pay our liabilities as they became due or that the class action filed by the Federal Prosecutor’s Office, an injunction was issued realizable value of our assets would thereafter be less than our liabilities. by a Brazilian Federal Court against the ANP, the Federal Government and GeoPark Brazil on December 13, 2013. Due to the injunction and a decision Additionally, any decision to pay dividends in the future, and the amount from the Board of ANP GeoPark Brazil could not proceed to execute the of any distributions, is at the discretion of our board of directors and concession agreement, and cannot do so until the injunction is either lifted our shareholders, and will depend on many factors, such as our results of or clarified as to what conditions and which type of conventional drilling operations, financial condition, cash requirements, prospects and other activities may be carried out by GeoPark Brazil. According to the terms of the factors. See “-Item 3. Key Information-D. Risk factors-Risks related to Court’s injunction, the ANP will first need to take certain actions, such as our common shares-We have never declared or paid, and do not intend to conducting studies that prove that drilling unconventional resources will not pay in the foreseeable future, cash dividends on our common shares, and, contaminate the dams and aquifers in the region. On February 21, 2014, consequently, your only opportunity to achieve a return on your investment GeoPark Brazil requested that the board of the ANP suspend the execution of the concession agreement (which entails delivery of the financial is if the price of our stock appreciates” and “-We are a holding company dependent upon dividends from our subsidiaries, which may be limited by guarantee and performance guarantee and payment of the signing bonus) law and by contract from making distributions to us, which would affect for six months with a possible extension of an additional six months, or until our ability to pay dividends on the common shares,” as well as “-Item 10. a firm court decision is reached that does not prevent GeoPark Brazil from Additional Information-B. Memorandum of association and bye-laws.” entering into the concession agreement. On April 16, 2014, the ANP’s Board enacted a resolution stating that all B. Significant changes A discussion of the significant changes in our business can be found under proceedings related to the award of the concession of Block PN-T-597 to “-Item 4. Information on the Company-B. Business Overview-Recent GeoPark Brazil were suspended. Developments.” Due to similar law suits with the same types of claims filed in the states of Paraná and Bahia, where the Court decision was to carry out conventional ITEM 9. THE OFFER AND LISTING drilling activities we expect that such decisions may impact the law suit filed against us related to the Block PN-T-597, and also the ANP’s decision to suspend the process for not signing the concession agreement. A. Offering and listing details Not applicable. 164 GeoPark 20F B. Plan of distribution Not applicable. F. Expenses of the issue Not applicable. C. Markets On February 6, 2014 we completed our initial public offering and listed our common shares on the New York Stock Exchange, or NYSE. Our common shares have been listed on the NYSE under the symbol “GPRK” since February 7, 2014. They were previously listed on the AIM under the ITEM 10. ADDITIONAL INFORMATION A. Share capital Not applicable. symbol “GPK” until February 19, 2014, and, since 2009, have been admitted to trade on the Santiago Offshore Stock Exchange (Bolsa Offshore de la Bolsa B. Memorandum of association and bye-laws The following description of our memorandum of association and bye-laws de Comercio de Santiago) in Chile. We intend to de-register from the does not purport to be complete and is subject to, and qualified by reference Santiago Offshore Stock Exchange as soon as practicable. to, all of the provisions of our memorandum of association and bye-laws. The table below presents, for the periods indicated, the annual, quarterly and monthly high and low closing prices (in US$) of our common shares on General We are an exempted company with limited liability incorporated under the the NYSE. Annual price history 2014 (from February 7 through December 31, 2014) 2015 (through April 27, 2015) Quarterly price history 3rd Quarter 2014 4th Quarter 2014 1st Quarter 2015 2nd Quarter 2015 (through April 27, 2015) Monthly price history November 2014 December 2014 January 2015 February 2015 March 2015 April 2015 (through April 27, 2015) Source: Bloomberg D. Selling shareholders Not applicable. E. Dilution Not applicable. laws of Bermuda with registration number 33273 from the Registrar of Companies. The rights of our shareholders will be governed by Bermuda law Common shares and by our memorandum of association and bye-laws. Bermuda company law Average daily differs in some material respects from the laws generally applicable to Delaware trading corporations. Below is a summary of some of those material differences. High Low volume (US$ per share) (in shares) Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and to our shareholders. 11.00 5.48 11.00 9.64 5.48 5.49 8.50 6.61 5.48 4.75 4.40 5.49 4.92 3.60 9.17 4.92 3.60 47,795 40,535 Share capital and bye-laws Our share capital consists of common shares only. Our authorized share capital consists of 5,171,949,000 common shares of par value US$0.001 26,216 56,218 42,734 per share. As of the date of this annual report, there are 57,603,745 common shares outstanding. All of our issued and outstanding common shares are fully paid and nonassessable. We also have an employee incentive program, 3.72 30,701 pursuant to which we have granted share awards to our senior management and certain key employees. See “-Item 6. Directors, Senior Management and Employees.” 6.92 4.92 3.70 3.71 3.60 3.72 50,434 75,079 50,362 50,972 28,684 30,701 According to our bye-laws, if our share capital is divided into different classes of shares, the rights attached to any class (unless otherwise 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 writing of the holders of at least two-thirds of the issued shares of that class or with the sanction of a resolution passed by a majority of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum shall be two persons at least holding or representing by proxy one-third of the issued shares of the class. The rights conferred upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise expressly provided by the terms of issue of the shares of that class, be deemed to be varied by the creation or issue of further shares ranking pari passu therewith. GeoPark 20F 165 Our bye-laws give our board of directors the power to issue any unissued meetings of the board of directors shall be the presence of a majority of the shares of the company on such terms and conditions as it may determine, board of directors from time to time. subject to the terms of the bye-laws and any resolution of the shareholders to the contrary. Duties of directors Under Bermuda common law, members of a board of directors owe a Common shares Holders of our common shares are entitled to one vote per share on all fiduciary duty to the Company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties matters submitted to a vote of holders of common shares. Subject to of their office honestly. This duty has the following essential elements: (1) a preferences that may be applicable to any issued and outstanding preference duty to act in good faith in the best interests of the company; (2) a duty shares, holders of common shares are entitled to receive such dividends, not to make a personal profit from opportunities that arise from the office of if any, as may be declared from time to time by our board of directors director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise out of funds legally available for dividend payments. Holders of common powers for the purpose for which such powers were intended. The Bermuda shares have no redemption, sinking fund, conversion, exchange or other Companies Act also imposes a duty on directors of a Bermuda company, subscription rights. In the event of our liquidation, the holders of common to act honestly and in good faith, with a view to the best interests of the shares are entitled to share equally and ratably in our assets, if any, company, and to exercise the care, diligence and skill that a reasonably remaining after the payment of all of our debts and liabilities, subject to prudent person would exercise in comparable circumstances. In addition, any liquidation preference on any outstanding preference shares. the Bermuda Companies Act imposes various duties on directors with respect to certain matters of management and administration of the company. Board composition Our bye-laws provide that our board of directors will determine the size The Bermuda Companies Act provides that in any proceedings for negligence, of the board, provided that it shall be not be composed of fewer than three default, breach of duty or breach of trust against any director, if it appears directors. Our board of directors currently consists of seven directors. to a court that such officer is or may be liable in respect of the negligence, Election and removal of directors Our bye-laws provide that our directors shall hold office for such term as default, breach of duty or breach of trust, but that he has acted honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment, he ought fairly to be the shareholders shall determine or, in the absence of such determination, excused for the negligence, default, breach of duty or breach of trust, that until the next annual general meeting or until their successors are elected court may relieve him, either wholly or partly, from any liability on such terms or appointed or their office is otherwise vacated. Directors whose office has as the court may think fit. This provision has been interpreted to apply only expired may offer themselves for re-election at each election of the directors. to actions brought by or on behalf of the company against the directors. Under our bye-laws, a director may be removed by a resolution adopted by By comparison, under Delaware law, the business and affairs of a corporation 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a duty of care and a duty of loyalty. in accordance with the provisions of our bye-laws. Notice convened for the The duty of care requires that directors act in an informed and deliberate purpose of removing the director, containing a statement of the intention to do manner and to inform themselves, prior to making a business decision, of all so, must be served on such director not less than 14 days before the meeting. relevant material information reasonably available to them. The duty of Any vacancy created by the removal of a director at a special general meeting of corporate employees. The duty of loyalty is the duty to act in good faith, may be filled at that meeting by the election of another director in his or not out of self-interest, and in a manner which the director reasonably her place or, in the absence of any such election, by the board of directors. believes to be in the best interests of the shareholders. A party challenging Any other vacancy, including a newly created directorship, may be filled the propriety of a decision of a board of directors bears the burden of care also requires that directors exercise care in overseeing the conduct by our board of directors. Proceedings of board of directors Our bye-laws provide that our business shall be managed by or under the rebutting the presumptions afforded to directors by the “business judgment rule.” If the presumption is not rebutted, the business judgment rule attaches to protect the directors and their decisions. Where, however, the presumption is rebutted, the directors bear the burden of demonstrating the fairness direction of our board of directors. Our board of directors may act by the of the relevant transaction. Notwithstanding the foregoing, Delaware courts affirmative vote of a majority of the directors present at a meeting at which a subject directors’ conduct to enhanced scrutiny in respect of defensive quorum is present. The quorum necessary for the transaction of business at actions taken in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation. 166 GeoPark 20F Interested directors Pursuant to our bye-laws, a director shall declare the nature of his interest in meeting of shareholders each calendar year, unless the shareholders in a general meeting, elect to dispense with the holding of annual general any contract or arrangement with the company as required by the Bermuda meetings. Under Bermuda law and our bye-laws, a special general meeting Companies Act. A director so interested shall not, except in particular of shareholders may be called by the board of directors or the chairman circumstances set out in our bye-laws, be entitled to vote or be counted and may be called upon the requisition of shareholders holding not less than in the quorum at a meeting in relation to any resolution in which he has an 10% of the paid-up capital of the company carrying the right to vote at interest, which is to his knowledge, a material interest (otherwise than by general meetings of shareholders. virtue of his interest in shares or debentures or other securities of or otherwise in or through the company). In addition, the director will not be Our bye-laws provide that, at any general meeting of the shareholders, the liable to us for any profit realized from the transaction. In contrast, under presence in person or by proxy of two or more shareholders representing Delaware law, such a contract or arrangement is voidable unless it is in excess of 50% of the total issued voting shares of the company shall approved by a majority of disinterested directors or by a vote of shareholders, constitute a quorum for the transaction of business unless the company only in each case if the material facts as to the interested director’s relationship has one shareholder, in which case such shareholder shall constitute a or interests are disclosed or are known to the disinterested directors or quorum. Unless otherwise required by law or by our bye-laws, shareholder shareholders, or such contract or arrangement is fair to the corporation action requires a resolution adopted by a majority of votes cast by as of the time it is approved or ratified. Additionally, such interested director shareholders at a general meeting at which a quorum is present. could be held liable for a transaction in which such director derived an improper personal benefit. Indemnification of directors and officers Bermuda law provides generally that a Bermuda company may indemnify Shareholder proposals Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group its directors and officers against any loss arising from or liability which by composed of at least 100 or more shareholders may require a proposal to virtue of any rule of law would otherwise be imposed on them in respect of be submitted to an annual general meeting of shareholders. Under our any negligence, default, breach of duty or breach of trust except in cases bye-laws, any shareholders wishing to nominate a person for election as a where such liability arises from fraud or dishonesty of which such director or director or propose business to be transacted at a meeting of shareholders officer may be guilty in relation to the company. must provide (among other things) advance notice, as set out in our bye-laws. Shareholders may only propose a person for election as a director Our bye-laws provide that we shall indemnify our officers and directors at an annual general meeting. in respect of their actions and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which such director is not legally entitled, and (by incorporation of the provisions of Shareholder action by written consent Our bye-laws provide that, except for the removal of auditors and the Bermuda Companies Act) that we may advance monies to our officers and directors for costs, charges and expenses incurred by our officers and directors, any actions which shareholders may take at a general meeting of shareholders may be taken by the shareholders through the unanimous directors in defending any civil or criminal proceeding against them on the written consent of the shareholders who would be entitled to vote on the condition that the officers and directors repay the monies if any allegation of matter at the general meeting. fraud or dishonesty is proved against them provided, however, that, if the Bermuda Companies Act requires, an advancement of expenses shall be made only upon delivery to the Company of an undertaking ,by or on behalf Amendment of memorandum of association and bye-laws Our memorandum of association and bye-laws may be amended with the of such indemnitee, to repay all amounts so advanced if it shall ultimately be approval of a majority of our board of directors and by a resolution by a determined by final judicial decision from which there is no further right to majority of the votes cast by shareholders who (being entitled to do so) vote appeal that such indemnitee is not entitled to be indemnified for such expenses in person or by proxy at any general meeting of the shareholders in under this Bye-law or otherwise. Our bye-laws provide that the company and accordance with the provisions of the bye-laws. the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company’s directors or officers for any act or failure to act in the performance of such director’s or Business combinations A Bermuda company may engage in a business combination pursuant to a officer’s duties, except in respect of any fraud or dishonesty. tender offer, amalgamation, merger or sale of assets. The amalgamation Meetings of shareholders Under Bermuda law, a company is required to convene the annual general or merger of a Bermuda company with another company generally requires the amalgamation or merger agreement to be approved by the company’s GeoPark 20F 167 board of directors and by its shareholders. Shareholder approval is not court for appraisal of the value of their shares within one month of the required where (a) a holding company and one or more of its wholly-owned compulsory acquisition notice. If a dissenting shareholder is successful in subsidiary companies amalgamate or merge or (b) two or more wholly- obtaining a higher valuation, that valuation must be paid to all shareholders owned subsidiary companies of the same holding company amalgamate being squeezed out. or merge. Under the Bermuda Companies Act (save for such “short-form amalgamations”), unless a company’s bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to Dividends and repurchase of shares Pursuant to our bye-laws, our board of directors has the authority to declare approve the amalgamation or merger agreement, and the quorum for dividends and authorize the repurchase of shares subject to applicable law. such meeting must be two persons holding or representing more than one- Under Bermuda law, a company may not declare or pay a dividend if there are third of the issued shares of the company. Our bye-laws provide that an reasonable grounds for believing that the company is, or would after the amalgamation or merger will require the approval of our board of directors payment be, unable to pay its liabilities as they become due or the realizable and of our shareholders by a resolution adopted by 65% or more of the value of its assets would thereby be less than its liabilities. Under Bermuda votes cast by shareholders who (being entitled to do so) vote in person or law, a company cannot purchase its own shares if there are reasonable by proxy at any general meeting of the shareholders in accordance grounds for believing that the company is, or after the repurchase would be, with the provisions of the bye-laws. Under Bermuda law, in the event of unable to pay its liabilities as they become due. an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who is not satisfied that fair value has been offered for such shareholder’s shares may, within month of the notice Shareholder suits Class actions and derivative actions are generally not available to of the shareholders meeting, apply to the Supreme Court of Bermuda to shareholders under Bermuda law. The Bermuda courts, however, would appraise the value of those shares. ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act Under the Bermuda Companies Act, we are not required to seek the approval complained of is alleged to be beyond the corporate power of the company of our shareholders for the sale of all or substantially all of our assets. or illegal, or would result in the violation of the company’s memorandum However, Bermuda courts will view decisions of the English courts as highly of association or bye-laws. Furthermore, consideration would be given persuasive and English authorities suggest that such sales do require by a Bermuda court to acts that are alleged to constitute a fraud against the shareholder approval. Our bye-laws provide that the directors shall manage minority shareholders or where an act requires the approval of a greater the business of the Company and may exercise all such powers as are not, percentage of the company’s shareholders than that which actually by the Bermuda Companies Act or by these Bye-laws, required to be approved it. exercised by the Company in general meeting and may pay all expenses incurred in promoting and incorporating the company and may exercise all When the affairs of a company are being conducted in a manner which the powers of the Company including, but not by way of limitation, is oppressive or prejudicial to the interests of some part of the shareholders, the power to borrow money and to mortgage or charge all or any part of the undertaking property and assets (present and future) and uncalled capital one or more shareholders may apply under the Bermuda Companies Act for an order of the Supreme Court of Bermuda, which may make such order of the Company and to issue debentures and other securities, whether as it sees fit, including an order regulating the conduct of the company’s outright or as collateral security for any debt, liability or obligation of the affairs in the future or ordering the purchase of the shares of any shareholders Company or any other persons. by other shareholders or by the company. Under Bermuda law, where an offer is made for shares of a company and, within four months of the offer, the holders of not less than 90% of the shares Access to books and records and dissemination of information Members of the general public have a right to inspect the public documents not owned by the offeror, its subsidiaries or their nominees accept such of a company available at the office of the Registrar of Companies offer, the offeror may by notice require the non-tendering shareholders to in Bermuda. These documents include the company’s memorandum of transfer their shares on the terms of the offer. Dissenting shareholders do not association and any amendments thereto. The shareholders have the have express appraisal rights but are entitled to seek relief (within one month additional right to inspect the bye-laws of the company, minutes of general of the compulsory acquisition notice) from the court, which has power to meetings of shareholders and the company’s audited financial statements. make such orders as it thinks fit. Additionally, where one or more parties hold The company’s audited financial statements must be presented at the annual not less than 95% of the shares of a company, such parties may, pursuant general meeting of shareholders, unless the board and all the shareholders to a notice given to the remaining shareholders, acquire the shares of such agree to the waiving of the audited financials. The company’s share register is remaining shareholders. Dissenting shareholders have a right to apply to the open to inspection by shareholders and by members of the general public 168 GeoPark 20F without charge. A company is required to maintain its share register in does not describe all of the tax consequences that may be relevant in light Bermuda but may, subject to the provisions of the Bermuda Companies Act, of the U.S. Holder’s particular circumstances, including alternative minimum establish a branch register outside of Bermuda. Bermuda law does not, tax and Medicare contribution tax consequences and differing tax however, provide a general right for shareholders to inspect or obtain copies consequences applicable to a U.S. Holder subject to special rules, such as: of any other corporate records. • certain financial institutions; Registrar or transfer agent A register of holders of the common shares is maintained by Coson Corporate accounting; • a person holding common shares as part of a straddle, wash sale or Services Limited in Bermuda, and a branch register is maintained in the conversion transaction or entering into a constructive sale with respect to • a dealer or trader in securities who uses a mark-to-market method of tax United States by Computershare Trust Company, N.A., who serves as branch registrar and transfer agent. C. Material contracts See “-Item 4. Information on the Company-B. Business overview-Significant agreements.” D. Exchange controls Not applicable. E. Taxation The following summary contains a description of certain Bermudian, U.S. federal income, and Chilean tax consequences of the acquisition, ownership the common shares; • a person whose functional currency for U.S. federal income tax purposes is not the U.S. dollar; • a partnership or other entities classified as partnerships for U.S. federal income tax purposes; • 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 person who acquired our shares pursuant to the exercise of an employee stock option or otherwise as compensation; or • a person holding common shares in connection with a trade or business conducted outside of the United States. and disposition of our common shares. The summary is based upon the If an entity that is classified as a partnership for U.S. federal income tax tax laws of Bermuda, the United States, and Chile, and regulations thereunder purposes holds common shares, the U.S. federal income tax treatment of a as of the date hereof, which are subject to change. partner will generally depend on the status of the partner and the activities Bermuda tax consideration At the date of this annual report, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty of the partnership. Partnerships holding common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of their investment in our common shares. or inheritance tax payable by us or by our shareholders in respect of our This discussion is based on the Internal Revenue Code of 1986, as amended, common shares. We have obtained an assurance from the Minister of Finance or the Code, administrative pronouncements, judicial decisions, and final, of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any temporary and proposed Treasury regulations, all as of the date hereof, any of which is subject to change, possibly with retroactive effect. U.S. Holders tax computed on profits or income, or computed on any capital asset, should consult their tax advisers concerning the U.S. federal, state, local and gain or appreciation or any tax in the nature of estate duty or inheritance tax, foreign tax consequences of owning and disposing of our common shares such tax shall not, until March 31, 2035, be applicable to us or to any of our in their particular circumstances. operations or to our common shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal payable by us in respect of real property owned or leased by us in Bermuda. income tax purposes that is: We pay annual Bermuda government fees. • a citizen or individual resident of the United States; Material U.S. federal income tax considerations The following is a description of the material U.S. federal income tax consequences to U.S. Holders (as defined below) of owning and disposing of • a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or • an estate or trust the income of which is subject to U.S. federal income our common shares. This discussion is not a comprehensive description of taxation regardless of its source. all tax considerations that may be relevant to a particular person’s decision to hold our common shares. This discussion applies only to a U.S. Holder that This discussion assumes that we are not, and will not become, a passive holds our common shares as capital assets for tax purposes. In addition, it foreign investment company, as described below. GeoPark 20F 169 Taxation of distributions Distributions paid on our common shares, other than certain pro rata PFIC is made annually and is based upon the composition of our income and assets (including the income and assets of, among others, entities in which distributions of common shares, will generally be treated as dividends we hold at least a 25% interest), and the nature of our activities. to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not If we were a PFIC for any taxable year during which a U.S. Holder held maintain calculations of our earnings and profits under U.S. federal income our common shares, gain recognized by a U.S. Holder on a sale or other tax principles, it is expected that distributions will generally be reported disposition (including certain pledges) of our common shares would to U.S. Holders as dividends. Dividends paid by qualified foreign corporations generally be allocated ratably over the U.S. Holder’s holding period for the to certain non-corporate U.S. Holders may be taxable at favorable rates. common shares. The amounts allocated to the taxable year of the sale or A foreign corporation is treated as a qualified foreign corporation with other disposition and to any year before we became a PFIC would be taxed respect to dividends paid on stock that is readily tradable on a securities as ordinary income. The amount allocated to each other taxable year would market in the United States, such as the NYSE where our common shares be subject to tax at the highest rate in effect for individuals or corporations are traded. Non-corporate U.S. Holders should consult their tax advisers for that year, as appropriate, and an interest charge would be imposed on to determine whether the favorable rate will apply to dividends they receive the tax on such amount. Further, to the extent that any distribution received and whether they are subject to any special rules that limit their ability by a U.S. Holder on its common shares exceeds 125% of the average of the to be taxed at this favorable rate. annual distributions on the shares received during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, that distribution A dividend generally will be included in a U.S. Holder’s income when would be subject to taxation in the same manner as gain, as described received, will be treated as foreign-source income to U.S. Holders and will not immediately above. Certain elections may be available that would result be eligible for the dividends-received deduction generally available to U.S. in alternative treatments (such as mark-to-market treatment) of our common corporations under the Code with respect to dividends paid by domestic shares. U.S. Holders should consult their tax advisers to determine whether corporations. any of these elections would be available and, if so, what the consequences of the alternative treatments would be in their particular circumstances. Sale or other taxable disposition of common shares Subject to the passive foreign investment company rules described below, gain or loss realized on the sale or other taxable disposition of our common Information reporting and backup withholding Payments of dividends and sales proceeds that are made within the United shares will be capital gain or loss, and will be long-term capital gain or loss States or through certain U.S.-related financial intermediaries generally are if the U.S. Holder held our common shares for more than one year. subject to information reporting, and may be subject to backup withholding, Long-term capital gain of a non-corporate U.S. Holder is generally taxed at unless (1) the U.S. Holder is a corporation or other exempt recipient or (2) preferential rates. The deductibility of capital losses is subject to limitations. in the case of backup withholding, the U.S. Holder provides a correct The amount of the gain or loss will equal the difference between the U.S. taxpayer identification number and certifies that it is not subject to backup Holder’s tax basis in the common shares disposed of and the amount realized on the disposition. If a Chilean tax is withheld on the sale or disposition withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal of the common shares, a U.S. Holder’s amount realized will include the gross income tax liability and may entitle it to a refund, provided that the required amount of the proceeds of the sale or disposition before deduction of the information is timely furnished to the Internal Revenue Service. Chilean tax. See “-Chilean tax on transfers of shares” for a description of when a disposition may be subject to taxation by Chile. This gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. U.S. Chilean tax on transfers of shares In September 2012, Article 10 of the Chilean Income Tax Law Decree Law Holders should consult their tax advisers as to whether the Chilean tax on No. 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes gains may be creditable against the U.S. Holder’s U.S. federal income tax on the indirect transfer of shares, equity rights, interests or other rights in on foreign-source income from other sources. the equity, control or profits of a Chilean entity as well as transfers of other assets and property of permanent establishments or other businesses in Chile, Passive foreign investment company rules We believe that we were not a “passive foreign investment company,” or PFIC, or the Chilean Assets. The 2014 tax reform introduces a measure which obliges the company from which shares are transferred to pay taxes if the for U.S. federal income tax purposes for 2014, and we do not expect to be a entity which undertakes the transfer of shares fails to do so. PFIC in the foreseeable future. However, because the composition of our income and assets will vary over time, there can be no assurance that we will not be a PFIC for any taxable year. The determination of whether we are a The indirect transfer rules apply to sales of shares of an entity: • If such entity is an offshore holding company located in a black-listed tax 170 GeoPark 20F haven jurisdiction as determined by Chilean tax law, or a black-listed Based on information available to us, (i) no Chilean resident holds 5% or jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean more of our rights to equity, control or profits; or (ii) residents in black-listed resident holds 5% or more of such entity, or such entity’s rights to equity, jurisdictions hold 50% or more of our rights to equity, control or profits. control or profits, or 50% or more of such entity’s rights to equity or profits Therefore, we do not believe the indirect transfer rules will apply to transfers are held by residents in black-listed jurisdictions; or of our common shares, unless the shares or rights transferred represent • the shares or rights transferred represent 10% or more of the offshore 10% or more of the company and the other conditions described above are holding company (considering dispositions by related persons and over met (considering dispositions by related persons and over the preceding the preceding 12-month period) and the underlying Chilean Assets indirectly 12-month period). transferred, in the proportion indirectly owned by the seller, (a) are valued in an amount equal to or higher than UTA 210,000 (approximately However, there can be no assurance that, at any time in the future, a US$200 million) (adjusted by the Chilean inflation unit of reference) or Chilean resident will not hold 5% or more of our rights to equity, control or (b) represent 20% or more of the market value of the interest held by such profits or that residents in black-listed jurisdictions will not hold 50% or seller in such offshore holding company. more of our rights to equity, control or profits. If this were to occur, all sales of our common shares would be subject to the indirect transfer tax referred As a result of these rules, a capital gain tax of 35% will be applied by the to above. Chilean tax authorities to the sale of any of our common shares if either of the above alternative are met. This rate might be subject to change in the short Our expectations regarding the indirect transfer rules are based on our term. See “-Item 4. Information on the Company-B. Business Overview-Other understandings, analysis and interpretation of these enacted indirect transfer regulation of the oil and gas industry-Chile.” rules, which are subject to additional interpretation and rule-making by the Chilean authorities. As such, there is uncertainty relating to the application by As of December 31, 2014, our Chilean Assets represented more than UTA Chilean authorities of the indirect transfer rules on us. 210,000 and represent more than 20% of our market value. The 35% rate is calculated pursuant to one of the following methods, as shares-The transfer of our common shares may be subject to capital gains See “-Item 3. Key Information-D. Risk Factors-Risks related to our common determined by the seller: • the sale price of the shares minus the acquisition cost of such shares, multiplied by the percentage or proportion of the part of the underlying Chilean Assets’ fair market value (which assets are deemed to be “indirectly transferred” by virtue of the sale of shares) to the fair market value of the shares of the seller; or • the portion of the sales price of the shares equal to the proportion of the fair market value of the underlying Chilean Assets, minus the corresponding proportion in the tax cost of such Chilean Assets for the corresponding holding entity. 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 However, the seller may opt to be taxed as if the underlying Chilean Assets SEC, including annual reports on Form 20-F and reports on Form 6-K. You had been sold directly in which case a different set of tax rules may apply. 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. The tax is payable by the seller of the shares; however, the buyer shall make Information on the operation of the Public Reference Room may be obtained a provisional withholding unless the seller declares and pays the tax within by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an the month following the sale, payment, remittance or it is credited into Internet website that contains reports and other information about issuers, its account or is put at its disposal. Also, if the seller fails to declare and pay like us, that file electronically with the SEC. The address of that website is this tax, and the buyer has not complied with its withholding obligations, www.sec.gov. the Chilean tax authority (Servicio de Impuestos Internos) may charge such tax directly to any of them. In addition, the Chilean tax authority may require us, the seller, the buyer, or its representative in Chile, to file an affidavit with I. Subsidiary information Not applicable. the information necessary to assess this tax. GeoPark 20F 171 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 audited 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. D. American Depositary Shares Not applicable. 172 GeoPark 20F Part II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES procedures that: A. Defaults No matters to report. B. Arrears and delinquencies No matters to report. • pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; • provide reasonable assurance that transactions are recorded as necessary to 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 ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY of unauthorized acquisition, use or disposition of our assets that could have a HOLDERS AND USE OF PROCEEDS Not applicable. material effect on our financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over ITEM 15. CONTROLS AND PROCEDURES financial reporting cannot, and does not, provide absolute assurance of A. Disclosure Controls and Procedures As of December 31, 2014, under the supervision and with the participation 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, of our management, including our Chief Executive Officer and Chief Financial or that the degree of compliance with the policies or procedures may Officer, we performed an evaluation of the effectiveness of the design deteriorate. and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). There are inherent limitations to the Under the supervision and with the participation of our management, effectiveness of any disclosure controls and procedures system, including including our Chief Executive Officer, our Chief Financial Officer, and our the possibility of human error and circumventing or overriding them. Even if Director of Legal and Governance, we conducted an evaluation of the effective, disclosure controls and procedures can provide only reasonable effectiveness of our internal control over financial reporting as of December assurance of achieving their control objectives. 31, 2014, based on the criteria established in Internal Control-Integrated Framework of the Committee of Sponsoring Organizations of the Treadway Based on such evaluation, our Chief Executive Officer and Chief Financial Commission (2013). Officer concluded that our disclosure controls and procedures are effective to provide reasonable assurance that the information we are required Based on this assessment, management believes that, as of December 31, to disclose in the reports we file or submit under the Exchange Act is (1) 2014, its internal control over financial reporting was effective based on recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (2) accumulated and communicated to our management to allow timely decisions regarding required disclosures. those criteria. C. Attestation Report of the Registered Public Accounting Firm Not applicable. B. Management’s Annual Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining an D. Changes in Internal Control over Financial Reporting There have been changes in our internal control over financial reporting during the period covered by this annual report on Form 20-F that adequate internal control over financial reporting as defined in Rule 13a-15(f) have materially affected our internal control over financial reporting. under the Exchange Act. Our internal control over financial reporting is a process designed by, or enterprise resource planning system (“ERP”) with a view to making its under the supervision of, our principal executive and principal financial operations more efficient, improving process management and decision- officers, management and other personnel, to provide reasonable assurance making, and strengthening its internal control system. As part of this regarding the reliability of financial reporting and the preparation of our process, in 2014 GeoPark has successfully undertaken the implementation financial statements for external reporting purposes, in accordance with of this new ERP to its Colombian, Chilean, Brazilian and Argentinean generally accepted accounting principles. These include those policies and operations to support its business processes. In the year ended December 31, 2014, GeoPark implemented a new GeoPark 20F 173 ITEM 16. [RESERVED] Tax Fees Tax fees are fees billed for professional services for tax compliance, tax advice ITEM 16A. Audit committee financial expert and tax planning. We have determined that Mr. Peter Ryalls, Mr. Juan Cristóbal Pavez and Mr. Robert Bedingfield are independent, as such term is defined under SEC rules Pre-Approval Policies and Procedures Following the listing of our common shares on the NYSE, the Audit applicable to foreign private issuers. In addition, Mr. Robert Bedingfield and Committee proposes the appointment of the independent auditor to the Mr. Juan Cristobal Pavez are regarded as audit committee financial experts. Board to be put to shareholders for approval at the Annual General meeting. ITEM 16B. Code of Conduct The committee oversees the auditor selection process for new auditors and ensures key partners in the appointed firm are rotated in accordance with best practices. Also, following our NYSE listing, the Audit Committee We have adopted a code of conduct applicable to the board of directors is required to pre-approve the audit and non-audit fees and services and all employees. Since its effective date on September 24, 2012, we have performed by the Company’s auditors in order to assure that the provision not waived compliance with or amended the code of conduct. of such services does not impair the audit firm’s independence. ITEM 16C. Principal Accountant Fees and Services All of the audit fees, audit-related fees and tax fees described in this item 16C have been approved by the Audit Committee. ITEM 16D. Exemptions from the listing standards for audit committees [NONE] Amounts billed by Price Waterhouse & Co. S.R.L. for audit and other services were as follows: Audit fees Audit-related fees Tax fees Other fees paid Total 2014 2013 (in millions of US$) 0.62 - 0.28 0.54 1.44 0.81 0.03 0.26 0.33 1.43 Audit Fees 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 annual 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 Securities and Exchange Commission. 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 for fiscal years 2014 and 2013 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. 174 GeoPark 20F 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 2014. Total number Total number of common shares Maximum number (or approximate dollar value) purchased as part of common shares of publicly that may yet of common shares Average price paid per announced plans be purchased under purchased - common share (US$) - or programs - the plans or programs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 73,082 73,082 5.30 5.30 73,082 73,082 US$10 million US$10 million 2014 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(1) December 1 to December 31 Total (1) In December 2014, the Board of Directors has approved a program to repurchase up to US$10 million of common shares, par value US$0.001 ITEM 16F. Change in registrant’s certifying accountant Not applicable. per share of the Company. This Repurchase Program began on December 19, 2014 and expired on March 27, 2015. The Shares repurchased are used to ITEM 16G. Corporate governance offset, in part, any expected dilution effects resulting from the Company’s employee incentive schemes, including grants under the Company’s Stock Our common shares are listed on the New York Stock Exchange, Award Plan and the Limited Non-Executive Director Plan. or NYSE. We are therefore required to comply with certain of the NYSE’s corporate governance listing standards, or the NYSE Standards. As a foreign private issuer, we may follow our home country’s corporate governance practices in lieu of most of the NYSE Standards. Our corporate governance practices differ in certain significant respects from those that U.S. companies must adopt in order to maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed Company Manual, a brief, general summary of those differences is provided as follows. GeoPark 20F 175 Director independence The NYSE Standards require a majority of the membership of NYSE-listed Additional audit committee functions The NYSE standards require that audit committees of domestic companies company boards to be composed of independent directors. Neither to serve a number of functions in addition to reviewing and approving the Bermuda law, the law of our country of incorporation, nor our memorandum company’s financial statements, engaging auditors and assessing their of association or bye-laws require a majority of our board to consist of independence, and obtaining the legal and other professional advice of independent directors. experts when necessary. For instance, the NYSE Standards require that the audit committee meet independently with management in a separate Non-management directors’ executive sessions The NYSE Standards require non-management directors of NYSE-listed session in order to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review a report companies to meet at regularly scheduled executive sessions without by the independent auditors describing the firm’s internal quality-control management. Our memorandum of association and bye-laws do not require procedures and any issues raised by these procedures. Finally, audit our non-management directors to hold such meetings. committees are responsible for designing and implementing an internal Committee member composition The NYSE Standards require domestic NYSE-listed domestic companies audit function that assesses the company’s risk management processes and systems of internal control on an ongoing basis. to have a nominating/corporate governance committee and a compensation Foreign private issuers such as us are exempt from these additional committee that are composed entirely of independent directors. Bermuda requirements if home country practice is followed. Bermuda law does not law, the law of our country of incorporation, does not impose similar impose similar requirements, and consequently, our audit committee requirements. does not perform these additional functions. Independence of the compensation committee and its advisers On January 11, 2013, the SEC approved NYSE listing standards that require Miscellaneous In addition to the above differences, we are not required to: make our audit that the board of directors of a domestic listed company consider two factors and compensation committees prepare a written charter that addresses (in addition to the existing general independence tests) in the evaluation either purposes and responsibilities or performance evaluations in a manner of the independence of compensation committee members: (i) the source of that would satisfy the NYSE’s requirements; acquire shareholder approval compensation of the director, including any consulting, advisory or other of equity compensation plans in certain cases; or adopt and make publicly compensatory fees paid by the listed company, and (ii) whether the director available corporate governance guidelines. has an affiliate relationship with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. In addition, We are incorporated under, and are governed by, the laws of Bermuda. before selecting or receiving advice from a compensation consultant or other For a summary of some of the differences between provisions of Bermuda adviser, the compensation committee of a listed company will be required law applicable to us and the laws applicable to companies incorporated to take into consideration six specific factors, as well as all other factors relevant to an adviser’s independence. in Delaware and their shareholders, See “-Item 10. Additional Information-B. Memorandum of association and bye-laws.” Foreign private issuers such as us will be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar ITEM 16H. Mine safety disclosure Not applicable. requirements, so we will not be required to implement the new 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 remuneration committee to consider the independence of any advisers that assist them in fulfilling their duties. 176 GeoPark 20F Part III ITEM 17. Financial statements We have responded to Item 18 in lieu of this item. ITEM 19. Exhibits ITEM 18. Financial statements Financial Statements are filed as part of this annual report, see pages 185 to to Exhibit 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on this Annual Report. September 9, 2013). Exhibit no. Description 1.1 Certificate of Incorporation (incorporated herein by reference 1.2 Memorandum of Association (incorporated herein by reference 1.3 1.4 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). 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). 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). GeoPark 20F 177 Exhibit no. Description 4.1 Special Contract for the Exploration and Exploitation of Exhibit no. Description 4.8 Subscription Agreement, dated December 18, 2012, among Hydrocarbons, Fell Block, dated April 29, 1997, among the LG International Corporation, GeoPark Chile Limited Agencia Republic of Chile, the Chilean Empresa Nacional de Petróleo en Chile, GeoPark Colombia S.A. and GeoPark Holdings (ENAP) and Cordex Petroleums Inc. (incorporated herein Limited (incorporated herein by reference to Exhibit 10.8 to by reference to Exhibit 10.1 to the Company’s Registration the Company’s Registration Statement on Form F-1 Statement on Form F-1 (File No. 333-191068) filed with (File No. 333-191068) filed with the SEC on September 9, 2013). the SEC on September 9, 2013). 4.9 Shareholders’ Agreement, dated December 18, 2012, among 4.2 Exploration and Production Contract regarding exploration LG International Corporation, GeoPark Chile Limited Agencia for and exploitation of hydrocarbons in the La Cuerva en Chile and GeoPark Colombia S.A. (incorporated herein Block, dated April 16, 2008, between the Colombian Agencia by reference to Exhibit 10.9 to the Company’s Registration Nacional de Hidrocarburos and Hupecol Caracara LLC Statement on Form F-1 (File No. 333-191068) filed with (incorporated herein by reference to Exhibit 10.l2 to the the SEC on September 9, 2013). Company’s Registration Statement on Form F-1 4.10 Subordinated Loan Agreement, dated December 18, 2012, (File No. 333-191068) filed with the SEC on September 9, 2013). between LG International Corporation and Winchester 4.3 Exploration and Production Contract regarding exploration Oil & Gas S.A. (incorporated herein by reference to Exhibit for and exploitation of hydrocarbons in the Llanos 34 Block, 10.10 to the Company’s Registration Statement on Form F-1 dated March 13, 2009, between the Colombian Agencia (File No. 333-191068) filed with the SEC on September 9, 2013). Nacional de Hidrocarburos and Unión Temporal Llanos 34 4.11 Subscription Agreement, dated October 18, 2011, among (incorporated herein by reference to Exhibit 10.3 to the LG International Corporation and GeoPark TdF S.A. Company’s Registration Statement on Form F-1 (incorporated herein by reference to Exhibit 10.11 to the (File No. 333-191068) filed with the SEC on September 9, 2013). Company’s Registration Statement on Form F-1 4.4 Subscription and Shareholders Agreement, dated February 7, (File No. 333-191068) filed with the SEC on September 9, 2013). 2006, among the International Finance Corporation, GeoPark 4.12 Shareholders’ Agreement, dated October 4, 2011, among Holdings Limited, Gerald O’Shaughnessy and James F. Park LG International Corporation, GeoPark TdF S.A. and GeoPark (incorporated herein by reference to Exhibit 10.4 to the Chile S.A. (incorporated herein by reference to Exhibit 10.12 Company’s Registration Statement on Form F-1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). (File No. 333-191068) filed with the SEC on September 9, 2013). 4.5 Purchase and Sale Agreement, dated March 26, 2012, 4.13 Quota Purchase Agreement, dated May 14, 2013, between between Hupecol Cuerva Holdings LLC and GeoPark Llanos S.A.S. Panoro Energy do Brasil Ltda. and GeoPark Brazil Exploracão (incorporated herein by reference to Exhibit 10.5 to e Producão de Petróleo e Gás Ltda (incorporated herein the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). by reference to Exhibit 10.13 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the 4.6 Subscription Agreement, dated May 20, 2011, among SEC on September 9, 2013). LG International Corporation, GeoPark Chile Limited Agencia 4.14 Purchase and Sale Agreement for Crude Oil and Condensate of en Chile, GeoPark Chile S.A. and GeoPark Holdings Limited Fell Block between Empresa Nacional del Petróleo (ENAP) and (incorporated herein by reference to Exhibit 10.6 to the GeoPark Fell S.p.A. (incorporated herein by reference to Exhibit Company’s Registration Statement on Form F-1 10.14 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). (File No. 333-191068) filed with the SEC on September 9, 2013). 4.7 Shareholders’ Agreement, dated May 20, 2011, among 4.15 Purchase and Sale Agreement for Natural Gas between LG International Corporation, GeoPark Chile Limited Agencia GeoPark Chile Limited, Agencia en Chile and Methanex en Chile and GeoPark Chile S.A. (incorporated herein Chile S.A. (incorporated herein by reference to Exhibit 10.15 by reference to Exhibit 10.7 to the Company’s Registration to the Company’s Registration Statement on Form F-1/A Statement on Form F-1 (File No. 333-191068) filed with (File No. 333-191068) filed with the SEC on October 10, 2013).† the SEC on September 9, 2013). 178 GeoPark 20F Exhibit no. Description 4.16 First Addendum and Amendment to Purchase and Sale Exhibit no. Description 12.1 Certification pursuant to section 302 of the Sarbanes-Oxley Act Agreement for Natural Gas between GeoPark Chile Limited, of 2002.* Agencia en Chile and Methanex Chile S.A. (incorporated herein 12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act by reference to Exhibit 10.16 to the Company’s Registration of 2002.* Statement on Form F-1/A (File No. 333-191068) filed with the 13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted SEC on October 10, 2013).† 4.17 Second Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited, Agencia en Chile and Methanex Chile S.A. (incorporated herein by reference to Exhibit 10.7 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on September 26, 2013). 13.2 15.1 15.2 99.1 pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* Consent of Price Waterhouse & Co. S.R.L., Argentina.* Consents of Degolyer & MacNaughton to use its report.* Reserves Report of DeGolyer and MacNaughton dated March 9, 2015, for reserves in Chile, Colombia, Brazil and Peru as of 4.18 Third Addendum and Amendment to Purchase and Sale December 31, 2014.* Agreement for Natural Gas between GeoPark Chile Limited, Agencia en Chile and Methanex Chile S.A. (incorporated herein * Filed with this Annual Report on Form 20-F. by reference to Exhibit 10.18 to the Company’s Registration † Confidential treatment of certain provisions of these exhibits has been Statement on Form F-1/A (File No. 333-191068) filed with the requested with the SEC. Omitted material for which confidential treatment SEC on October 10, 2013).† has been requested has been filed separately with the SEC. 4.19 Fourth Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited, Agencia en Chile and Methanex Chile S.A. (incorporated herein 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 on October 10, 2013).† 4.20 Members’ Agreement, dated January 8, 2014, among GeoPark 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). 4.21 Loan Agreement no. 4131, dated March 28, 2014, between Itaú BBA International plc and GeoPark Brasil Exploracão e Produção 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) 4.22 Addendum and Amendment to Loan Agreement no. 4131, dated March 12, 2015, between Itaú BBA International plc and GeoPark Brasil Exploracão e Produção de Petróleo e Gás Ltda.* 4.23 Fifth Addendum and Amendment to Purchase and Sale Agreement for Natural Gas between GeoPark Chile Limited, Agencia en Chile and Methanex Chile S.A. dated April 1, 2014.*† 8.1 Subsidiaries of GeoPark Limited (incorporated herein by reference to Exhibit 8.1 to the Company’s Annual Report on Form 20-F filed with the SEC on April 30, 2014).* GeoPark 20F 179 Glossary of Oil and Natural Gas Terms The terms defined in this section are used throughout this annual report: service well, or a stratigraphic test well as those items are defined below. “field” means an area consisting of a single reservoir or multiple reservoirs all “appraisal well” means a well drilled to further confirm and evaluate the grouped on or related to the same individual geological structural feature presence of hydrocarbons in a reservoir that has been discovered. and/or stratigraphic condition. There may be two or more reservoirs in a field “API” means the American Petroleum Institute’s inverted scale for denoting that are separated vertically by intervening impervious strata, or laterally the “light” or “heaviness” of crude oils and other liquid hydrocarbons. by local geologic barriers, or by both. Reservoirs that are associated by being “bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used in overlapping or adjacent fields may be treated as a single or common herein in reference to crude oil, condensate or natural gas liquids. operational field. The geological terms structural feature and stratigraphic “bcf” means one billion cubic feet of natural gas. condition are intended to identify localized geological features as opposed to “boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil. “boepd” means barrels of oil equivalent per day. “bopd” means barrels of oil per day. the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. “formation” means a layer of rock which has distinct characteristics that differ from nearby rock. “mbbl” means one thousand barrels of crude oil, condensate or natural gas “British thermal unit” or “btu” means the heat required to raise the liquids. temperature of a one-pound mass of water from 58.5 to 59.5 degrees “mboe” means one thousand barrels of oil equivalent. Fahrenheit. “mcf” means one thousand cubic feet of natural gas. “basin” means a large natural depression on the earth’s surface in which “Measurements” include: sediments generally brought by water accumulate. • “m” or “meter” means one meter, which equals approximately 3.28084 feet; “CEOP” (Contrato Especial de Operación) means a special operating contract • “km” means one kilometer, which equals approximately 0.621371 miles; the Chilean signs with a company or a consortium of companies for the • “sq. km” means one square kilometer, which equals approximately exploration and exploitation of hydrocarbon wells 247.1 acres; “completion” means the process of treating a drilled well followed by • “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent the installation of permanent equipment for the production of natural gas to approximately 0.15898 cubic meters; or oil, or in the case of a dry hole, the reporting of abandonment to the • “boe” means one barrel of oil equivalent, which equals approximately appropriate agency. 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of “developed acreage” means the number of acres that are allocated or natural gas to one barrel of oil; assignable to productive wells or wells capable of production. • “cf” means one cubic foot; “developed reserves” are expected quantities to be recovered from existing • “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, wells and facilities. Reserves are considered developed only after the respectively; necessary equipment has been installed or when the costs to do so • “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, are relatively minor compared to the cost of a well. Where required facilities respectively; become unavailable, it may be necessary to reclassify developed reserves as undeveloped. • “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, respectively; and “development well” means a well drilled within the proved area of an oil or • “pd” means per day. gas reservoir to the depth of a stratigraphic horizon known to be productive. “metric ton” or “MT” means one thousand kilograms. Assuming standard “dry hole” means a well found to be incapable of producing hydrocarbons quality oil, one metric ton equals 7.9 bbl. in sufficient quantities such that proceeds from the sale of such production “mmbbl” means one million barrels of crude oil, condensate or natural gas exceed production expenses and taxes. liquids. “E&P Contract” means exploration and production contract “mmboe” means one million barrels of oil equivalent. “economic interest” means an indirect participation interest in the net “mmbtu” means one million British thermal units. revenues from a given block based on bilateral agreements with the “NYMEX” means The New York Mercantile Exchange. concessionaires. “net acres” means the percentage of total acres an owner has out of a “economically producible” means a resource that generates revenue that particular number of acres, or a specified tract. An owner who has a 50% exceeds, or is reasonably expected to exceed, the costs of the operation. “exploratory well” means a well drilled to find and produce oil or gas in an interest in 100 acres owns 50 net acres. “productive well” means a well that is found to be capable of producing unproved area, to find a new reservoir in a field previously found to be hydrocarbons in sufficient quantities such that proceeds from the sale of the productive of oil or gas in another reservoir, or to extend a known reservoir. production exceed production expenses and taxes. Generally, an exploratory well is any well that is not a development well, a “prospect” means a potential trap which may contain hydrocarbons and is 180 GeoPark 20F supported by the necessary amount and quality of geologic and geophysical reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing, data to indicate a probability of oil and/or natural gas accumulation ready and is often established by regulatory agencies). to be drilled. The five required elements (generation, migration, reservoir, “spud” means the very beginning of drilling operations of a new well, seal and trap) must be present for a prospect to work and if any of them fail occurring when the drilling bit penetrates the surface utilizing a drilling rig neither oil nor natural gas will be present, at least not in commercial volumes. capable of drilling the well to the authorized total depth. “proved developed reserves” means those proved reserves that can be “stratigraphic test well” means a drilling effort, geologically directed, expected to be recovered through existing wells and facilities and by existing to obtain information pertaining to a specific geologic condition. Such wells operating methods. customarily are drilled without the intention of being completed for “proved reserves” means estimated quantities of crude oil, natural gas, and hydrocarbon production. This classification also includes tests identified as natural gas liquids which geological and engineering data demonstrate with core tests and all types of expendable holes related to hydrocarbon reasonable certainty to be economically recoverable in future years from exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved drilled in a proved area, or (ii) development-type, if drilled in a proved area. “undeveloped reserves” are quantities expected to be recovered through recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2). “proved undeveloped reserves” means are those proved reserves that future investments: (1) from new wells on undrilled acreage in known accumulation, (2) from deepening existing wells to a different (but known) are expected to be recovered from future wells and facilities, including future reservoir, (3) from infill wells that will increase recover, or (4) where a improved recovery projects which are anticipated with a high degree of relatively large expenditure (e.g., when compared to the cost of drilling a new certainty in reservoirs which have previously shown favorable response to well) is required to (a) recomplete an existing well or (b) install production improved recovery projects. or transportation facilities for primary or improved recovery projects. “reasonable certainty” means a high degree of confidence. “unit” means the joining of all or substantially all interests in a reservoir “recompletion” means the process of re-entering an existing wellbore that or field, rather than a single tract, to provide for development and operation is either producing or not producing and completing new reservoirs in without regard to separate property interests. Also, the area covered by a an attempt to establish or increase existing production. unitization agreement. “reserves” means estimated remaining quantities of oil and gas and related “wellbore” means the hole drilled by the bit that is equipped for oil or gas substances anticipated to be economically producible, as of a given date, production on a completed well. Also called well or borehole. by application of development projects to known accumulations. In addition, “working interest” means the right granted to the lessee of a property to there must exist, or there must be a reasonable expectation that there explore for and to produce and own oil, gas, or other minerals. The working will exist, a revenue interest in the production, installed means of delivering interest owners bear the exploration, development, and operating costs oil, gas, or related substances to market, and all permits and financing on either a cash, penalty, or carried basis. required to implement the project. “workover” means operations in a producing well to restore or increase “reservoir” means a porous and permeable underground formation production. containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. “royalty” means a fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance. “service well” means a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation, or injection for in-situ combustion. “shale” means a fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps. “spacing” means the distance between wells producing from the same GeoPark 20F 181 Index to Consolidated Financial Statements Audited Annual Consolidated Financial Statements-GeoPark Limited Report of Independent Registered Public Accounting Firm 182 Consolidated Statements of Income and Comprehensive Income for the Fiscal Years Ended December 31, 2014, 2013 and 2012 Consolidated Statement of Financial Position as of December 31, 2014 and 2013 Consolidated Statements of Changes in Shareholders’ Equity for the Fiscal Years Ended December 31, 2014, 2013, 2012 Consolidated Statements of Cash Flows for the Fiscal Years ended December 31, 2014, 2013, 2012 Notes to the Audited Annual Consolidated Financial Statements for the Fiscal Years Ended December 31, 2014, 2013 and 2012 183 184 185 186 187 182 GeoPark 20F GeoPark 20F 183 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, 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 19, 2015 184 GeoPark 20F Consolidated Statement of Income Amounts in US$ ´000 Note 2014 2013 2012 Net revenue Production costs Gross profit Exploration costs Administrative costs Selling expenses Impairment loss for non-financial assets Other operating (loss)/income Operating profit Financial results Bargain purchase gain on acquisition of subsidiaries Profit before income tax Income tax Profit for the year Attributable to: Owners of the Company Non-controlling interest Earnings per share (in US$) for profit attributable to owners of the Company - basic Earnings per share (in US$) for profit attributable to owners of the Company - diluted 7 8 11 12 13 38 14 34 16 18 18 428,734 (229,650) 199,084 (43,369) (48,164) (24,428) (9,430) (1,849) 71,844 338,353 (179,643) 158,710 (16,254) (46,584) (17,252) - 5,344 83,964 (50,719) (33,876) - - 21,125 50,088 (5,195) 15,930 (15,154) 34,934 7,512 8,418 0.13 0.13 22,012 12,922 0.50 0.47 250,478 (129,235) 121,243 (27,890) (28,798) (24,631) - 823 40,747 (16,308) 8,401 32,840 (14,394) 18,446 11,879 6,567 0.28 0.27 Consolidated Statement of Comprehensive Income Amounts in US$ ´000 2014 2013 2012 Profit for the year Other comprehensive income: Items that may be subsequently reclassified to profit Currency translation difference Total comprehensive income for the year 15,930 34,934 18,446 (2,448) 13,482 (1,956) 32,978 - 18,446 Attributable to: Owners of the Company Non-controlling interest 5,064 8,418 20,056 12,922 11,879 6,567 The notes on pages 189 to 238 are an integral part of these consolidated financial statements. GeoPark 20F 185 Consolidated Statement of Financial Position Amounts in US$ ´000 Note 2014 2013 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 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 Retained earnings (accumulated losses) Attributable to owners of the Company Non-controlling interest Total equity Liabilities Non current liabilities Borrowings Provisions and other long-term liabilities Deferred income tax liability Trade and other payables Total non current liabilities Current liabilities Borrowings Current income tax liabilities Trade and other payables Total current liabilities Total liabilities Total equity and liabilities 19 21 24 17 23 22 23 23 21 24 25 26 27 17 28 26 28 790,767 595,446 1,253 12,979 33,195 349 11,454 5,168 13,358 6,361 838,543 631,787 8,532 36,917 13,993 13,459 127,672 200,573 1,039,116 58 210,886 124,017 40,596 375,557 103,569 479,126 8,122 42,628 35,764 6,979 121,135 214,628 846,415 44 120,426 126,465 23,906 270,841 95,116 365,957 342,440 290,457 46,910 30,065 16,583 33,076 23,087 8,344 435,998 354,964 27,153 7,935 88,904 123,992 559,990 1,039,116 26,630 7,231 91,633 125,494 480,458 846,415 The financial statements were approved by the Board of Directors on 19 March 2015. The notes on pages 189 to 238 are an integral part of these consolidated financial statements. 186 GeoPark 20F Consolidated Statement of Changes in Equity Attributable to owners of the Company Retained earnings Non- Share capital(1) 43 Share premium 112,231 Other Translation (accumulated controlling reserve 114,270 reserve 894 losses) (18,549) interest 41,763 Total 250,652 Amount in US$ ´000 Equity at 1 January 2012 Comprehensive income: Profit for the year Total comprehensive income for the year 2012 Transactions with owners: Proceeds from transaction with non-controlling interest (Notes 25 and 34) Share-based payment (Note 29) Total 2012 - - - - - - - - 4,586 4,586 Balances at 31 December 2012 43 116,817 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 - - - - 1 - 1 - - - - 4,049 (440) 3,609 Comprehensive income: Profit for the year Currency translation differences Total comprehensive income for the year 2014 Transactions with owners: - - - - - - Proceeds from issue of shares 14 90,848 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 (1) See Note 1. - - - 14 58 - - (388) 90,460 - - 13,257 - 13,257 127,527 - - - - - - - - - - - - - - - The notes on pages 189 to 238 are an integral part of these consolidated financial statements. 210,886 127,527 (3,510) Balances at 31 December 2013 44 120,426 127,527 (1,062) - - - - - - - - - - - - - - 11,879 6,567 18,446 11,879 6,567 18,446 - 24,335 37,592 810 810 - 24,335 72,665 894 (5,860) - 22,012 12,922 (1,956) - - 5,396 42,988 312,086 34,934 (1,956) (1,956) 22,012 12,922 32,978 - 7,754 - 7,754 23,906 7,512 - 9,529 - - 9,529 95,116 8,418 - 9,529 11,804 (440) 20,893 365,957 15,930 (2,448) - (2,448) (2,448) 7,512 8,418 13,482 - - 9,178 - 9,178 40,596 - 90,862 35 - - 35 103,569 35 9,178 (388) 99,687 479,126 GeoPark 20F 187 Consolidated Statement of Cash Flow Amounts in US$ '000 Note 2014 2013 2012 Cash flows from operating activities Income for the year Adjustments for: Income tax for the year Depreciation of the year Allowance for doubtful accounts Loss on disposal of property, plant and equipment Impairment loss Write-off of unsuccessful efforts Accrual of interest on borrowings Amortisation of other long-term liabilities Unwinding of long-term liabilities Accrual of share-based payment Bargain purchase gain on acquisition of subsidiaries Deferred income Exchange difference on borrowings 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 16 9 13-23 38 11 27 27 10 34 27 14 5 34 15,930 34,934 18,446 5,195 101,657 741 591 9,430 30,367 25,754 (468) 1,972 8,373 - - 19,163 (1,306) 13,347 230,746 (238,047) (114,967) 8,973 15,154 70,200 - 575 - 10,962 22,085 (1,165) 1,523 9,167 - - - (4,040) (32,100) 127,295 (215,234) - 6,734 14,394 53,317 - 546 - 25,552 12,513 (2,143) 1,262 5,396 (8,401) 5,550 - (408) 3,403 129,427 (195,829) (105,303) - Cash flows used in investing activities - net (344,041) (208,500) (301,132) 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 Cash flows from financing activities - net 67,633 35 16,563 90,862 (388) (8,344) (17,087) (24,558) 124,716 307,259 40,667 8,344 3,442 (440) - (179,360) (15,894) 164,018 37,200 12,452 - - - - (12,382) (10,895) 26,375 Net increase (decrease) in cash and cash equivalents 11,421 82,813 (145,330) Cash and cash equivalents at 1 January Currency translation differences Cash and cash equivalents at the end of the year 121,105 (4,854) 127,672 38,292 - 121,105 Ending Cash and cash equivalents are specified as follows: Cash in bank Cash in hand Bank overdrafts Cash and cash equivalents 127,560 121,113 112 - 22 (30) 127,672 121,105 183,622 - 38,292 48,268 24 (10,000) 38,292 The notes on pages 189 to 238 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. 188 GeoPark 20F Notes Note 1 General information The transaction is subject to customary conditions, certain license modifications and a presidential decree (see Note 34.d). GeoPark Limited (the Company) is a company incorporated under the laws Additionally, the Company was awarded with two new blocks in Argentina of Bermuda. The Registered office address is Cumberland House, 9th Floor, in which the operator will be Pluspetrol: Puelen and Sierra del Nevado in 1 Victoria Street, Hamilton HM 11, Bermuda. the Neuquén Basin. The Company is the operator of the Del Mosquito Block On 7 February 2014, the Securities and Exchange Commission (“SEC”) in Argentina. declared effective the Company’s registration statement upon which These consolidated financial statements were authorised for issue by the 13,999,700 shares were issued at a price of US$ 7 per share, including over- Board of Directors on 19 March 2015. allotment option. Gross proceeds from the offering totalled US$ 98 million. As a result, the Company commenced trading on the New York Stock Exchange (“NYSE”) under the ticker symbol GPRK. Also its shares Note 2 are authorized for trading on the Santiago Off-Shore Stock Exchange. Summary of significant accounting policies Subsequently, the Company listing cancellation on the AIM London Stock Exchange became effective on 19 February 2014. The principal accounting policies applied in the preparation of these The principal activity of the Company and its subsidiaries (“the Group”) are consistently applied to the years presented, unless otherwise stated. consolidated financial statements are set out below. These policies have been exploration, development and production for oil and gas reserves in Chile, Colombia, Brazil, Peru and Argentina. The Group has working interests and/or economic interests in 31 hydrocarbon blocks. 2.1 Basis of preparation The consolidated financial statements of GeoPark Limited have been prepared in accordance with International Financial Reporting Standards In Chile the Group operates 6 blocks: Fell Block, Otway Block, Tranquilo Block (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). and Isla Norte, Flamenco and Campanario blocks in Tierra del Fuego. By acquiring three privately held companies in 2012, the Company obtained of United States Dollars and all values are rounded to the nearest thousand and maintained working interests and/or economic interests in 9 blocks (US$'000), except where otherwise indicated. located in the Llanos, Magdalena and Catatumbo basins in Colombia. In July and November 2014, the Company expanded its operations in Colombia The consolidated financial statements have been prepared on a historical The consolidated financial statements are presented in thousands (US$´000) through two new blocks: VIM-3 Block in the Lower Magdalena Basin and CPO- cost basis. 4 Block in the Llanos Basin (see Note 34), respectively. The Company is the operator in 6 of the 11 blocks in Colombia. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management In May 2013, the Company has extended its footprint into Brazil since it has to exercise its judgement in the process of applying the Group’s accounting been awarded 7 new licenses in the Brazilian Round 11 of which two are policies. The areas involving a higher degree of judgement or complexity, in the Reconcavo Basin in the State of Bahia and five are in the Potiguar Basin or areas where assumptions and estimates are significant to the consolidated in the State of Rio Grande do Norte. In addition, in November 2013, the financial statements are disclosed in this note under the title “Accounting Company has also been awarded 2 new concessions in a new international estimates and assumptions”. bidding round, Round 12, in the Parnaíba Basin in the State of Maranhão and Sergipe Alagoas Basin in the State of Alagoas, subject to removal of 2.1.1 Changes in accounting policy and disclosure injunction for Block PN-T-597 (see Note 34.c). On 31 March 2014, the Company acquired a 10% working interest in the New and amended standards adopted by the Group The following standards have been adopted by the Group for the first time offshore Manatí gas field, the largest natural gas producing field in Brazil. for the financial year beginning on or after 1 January 2014: The Manatí Field is operated by Petrobras (see Note 34). In the fourth quarter of 2014, the Company signed an agreement to acquire and liability offsetting. These amendments are to the application guidance an interest on the Morona Block in Peru, which belongs to Marañón Basin. in IAS 32, ‘Financial instruments: Presentation’, and clarify some of the Amendment to IAS 32, ‘Financial instruments: Presentation’ on asset GeoPark 20F 189 requirements for offsetting financial assets and financial liabilities on the Amendments to IFRS 10 and IAS 28 regarding the sale or contribution of balance sheet. assets between an investor and its associate or joint venture. These amendments address an inconsistency between IFRS 10 and IAS 28 in the Amendment to IAS 36, ‘Impairment of assets’ on recoverable amount sale or contribution of assets between an investor and its associate or disclosures. This amendment addresses the disclosure of information about joint venture. A full gain or loss is recognised when a transaction involves the recoverable amount of impaired assets if that amount is based on fair a business. A partial gain or loss is recognised when a transaction involves value less costs of disposal. assets that do not constitute a business, even if those assets are in a subsidiary. The Group is yet to assess amendment to IFRS 10 and 28’s full IFRIC 21, ‘Levies’, is an interpretation of IAS 37, ‘Provisions, contingent impact and intends to adopt it no later than the accounting period liabilities and contingent assets’. IAS 37 sets out criteria for the recognition beginning on or after 1 January 2016. of a liability, one of which is the requirement for the entity to have a present obligation as a result of a past event (known as an obligating event). Amendment to IAS 27, ‘Separate financial statements’ regarding the equity The interpretation addresses what the obligating event is that gives rise to method. The amendment allow entities to use the equity method to account the payment of a levy and when a liability should be recognised. for investments in subsidiaries, joint ventures and associates in their separate financial statements. The Group is yet to assess amendment to IAS 27’s full Amendment to IAS 19, ‘Employee benefits’ regarding employee or third impact and intends to adopt it no later than the accounting period beginning party contributions to defined benefit plans. The amendment applies on or after 1 January 2016. to contributions from employees or third parties to defined benefit plans and clarifies the treatment of such contributions. The amendment distinguishes Annual improvements 2014. These annual improvements amend standards between contributions that are linked to service only in the period in which from the 2012 - 2014 reporting cycle. It includes changes to: they arise and those linked to service in more than one period. The objective of the amendment is to simplify the accounting for contributions that are • IAS 19,’Employee benefits’ - The amendment clarifies that, when independent of the number of years of employee service, for example determining the discount rate for post-employment benefit obligations, employee contributions that are calculated according to a fixed percentage it is the currency that the liabilities are denominated in that is important, not of salary. Entities with plans that require contributions that vary with service the country where they arise. The assessment of whether there is a deep will be required to recognise the benefit of those contributions over market in high-quality corporate bonds is based on corporate bonds in employee’s working lives. that currency, not corporate bonds in a particular country. Similarly, where there is no deep market in high-quality corporate bonds in that currency, Management assessed the relevance of new standards, amendments or government bonds in the relevant currency should be used. The amendment interpretations and concluded that their adoption did not have a significant is retrospective but limited to the beginning of the earliest period presented impact on these financial statements. and the Group is yet to assess its full impact and intends to adopt it no later than the accounting period beginning on or after 1 July 2016. New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2014 and not early adopted. IFRS 15, ‘Revenue from contracts with customers’. This is the converged standard on revenue recognition. It replaces IAS 11, ‘Construction contracts’, Amendment to IFRS 11, ‘Joint arrangements’ regarding acquisition of an IAS 18,’Revenue’ and related interpretations. Revenue is recognised when interest in a joint operation. This amendment provides new guidance on how a customer obtains control of a good or service. A customer obtains control to account for the acquisition of an interest in a joint venture operation when it has the ability to direct the use of and obtain the benefits from the that constitutes a business. The amendments require an investor to apply good or service. The core principle of IFRS 15 is that an entity recognises the principles of business combination accounting when it acquires an revenue to depict the transfer of promised goods or services to customers in interest in a joint operation that constitutes a ‘business’. The amendments an amount that reflects the consideration to which the entity expects to be are applicable to both the acquisition of the initial interest in a joint operation entitled in exchange for those goods or services. An entity recognises revenue and the acquisition of additional interest in the same joint operation. in accordance with that core principle by applying the following steps: However, a previously held interest is not re-measured when the acquisition - Step 1: Identify the contract(s) with a customer of an additional interest in the same joint operation results in retaining - Step 2: Identify the performance obligations in the contract joint control. The Group is yet to assess amendment to IFRS 11’s full impact - Step 3: Determine the transaction price and intends to adopt it no later than the accounting period beginning on - Step 4: Allocate the transaction price to the performance obligations in or after 1 January 2016. the contract 190 GeoPark 20F - Step 5: Recognise revenue when (or as) the entity satisfies a performance Considering macroeconomic environment conditions (see Note 37), the obligation performance of the operations, Group’s cash position and over 80% of its total indebtedness maturing in 2020, the Directors have formed a judgement, IFRS 15 also includes a cohesive set of disclosure requirements that will at the time of approving the financial statements, that there is a reasonable result in an entity providing users of financial statements with comprehensive expectation that the Group has adequate resources to meet all its obligations information about the nature, amount, timing and uncertainty of revenue for the foreseeable future. For this reason, the Directors have continued to and cash flows arising from the entity’s contracts with customers. The Group adopt the going concern basis in preparing the consolidated financial is yet to assess amendment to IFRS 15’s full impact and intends to adopt it no statements. later than the accounting period beginning on or after 1 January 2017. IFRS 9, ‘Financial instruments’. The complete version of IFRS 9 replaces most 2.3 Consolidation Subsidiaries are all entities (including structured entities) over which the group of the guidance in IAS 39. IFRS 9 retains but simplifies the mixed measurement has control. The Group controls an entity when the Group is exposed to, or model and establishes three primary measurement categories for financial has rights to, variable returns from its involvement with the entity and has the assets: amortised cost, fair value through OCI and fair value through P&L. ability to affect those returns through its power over the entity. Subsidiaries The basis of classification depends on the entity’s business model and the are fully consolidated from the date on which control is transferred to the contractual cash flow characteristics of the financial asset. Investments in equity Group. They are deconsolidated from the date that control ceases. instruments are required to be measured at fair value through profit or loss with the irrevocable option at inception to present changes in fair value in OCI. The Group applies the acquisition method to account for business There is now a new expected credit losses model that replaces the incurred combinations. The consideration transferred for the acquisition of a subsidiary loss impairment model used in IAS 39. For financial liabilities there were is the fair values of the assets transferred, the liabilities incurred to the no changes to classification and measurement except for the recognition of former owners of the acquiree and the equity interests issued by the Group. changes in own credit risk in other comprehensive income, for liabilities The consideration transferred includes the fair value of any asset or liability designated at fair value, through profit or loss. resulting from a contingent consideration arrangement. Identifiable assets IFRS 9 relaxes the requirements for hedge effectiveness by replacing combination are measured initially at their fair values at the acquisition date. acquired and liabilities and contingent liabilities assumed in a business the bright line hedge effectiveness tests. It requires an economic relationship between the hedged item and hedging instrument and for the ‘hedged ratio’ Acquisition-related costs are expensed as incurred. to be the same as the one management actually use for risk management purposes. Contemporaneous documentation is still required but is different The excess of the consideration transferred, the amount of any non- to that currently prepared under IAS 39. The Group is yet to assess controlling interest in the acquiree and the acquisition-date fair value of any amendment to IFRS 9’s full impact and intends to adopt it no later than the previous equity interest in the acquiree over the fair value of the identifiable accounting period beginning on or after 1 January 2018. net assets acquired is recorded as goodwill. If the total of consideration transferred, non-controlling interest recognised and previously held interest There are no other IFRSs or IFRIC interpretations that are not yet effective that measured is less than the fair value of the net assets of the subsidiary would be expected to have a material impact on the Group. acquired in the case of a bargain purchase, the difference is recognised Management assessed the relevance of other new standards, amendments or interpretations not yet effective and concluded that they are not relevant Intercompany transactions, balances and unrealised gains on transactions directly in the income statement. to Group. 2.2 Going concern The Directors regularly monitor the Group's cash position and liquidity between the Group and its subsidiaries are eliminated. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure risks throughout the year to ensure that it has sufficient funds to meet consistency with the accounting policies adopted by the Group. forecast operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors to enable the Group to manage the risk of any funding short 2.4 Segment reporting Operating segments are reported in a manner consistent with the internal falls and/or potential debt covenant breaches. reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing GeoPark 20F 191 performance of the operating segments, has been identified as the strategic steering committee that makes strategic decisions. This committee 2.8 Production costs Production costs include wages and salaries incurred to achieve consists of the CEO, COO, CFO and managers in charge of the Exploration, the net revenue for the year. Direct and indirect costs of raw materials Development, Drilling, Operations, SPEED and Finance departments. and consumables, rentals and leasing, property, plant and equipment This committee reviews the Group’s internal reporting in order to assess depreciation and royalties are also included within this account. performance and allocate resources. Management has determined the operating segments based on these reports. 2.5 Foreign currency translation 2.9 Financial costs Financial costs include interest expenses, realised and unrealised gains and losses arising from transactions in foreign currencies and the amortisation of financial assets and liabilities. The Company has capitalised borrowing a) Functional and presentation currency The consolidated financial statements are presented in US Dollars, which is cost for wells and facilities that were initiated after 1 January 2009. Amounts capitalised during the year totalled US$ 3,112,317 (US$ 1,312,953 in 2013 the Group’s presentation currency. and US$ 1,368,952 in 2012). Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which 2.10 Property, plant and equipment Property, plant and equipment are stated at historical cost less depreciation the entity operates (the “functional currency”). The functional currency of and impairment charge, if applicable. Historical cost includes expenditure Group companies incorporated in Chile, Colombia, Peru and Argentina is the that is directly attributable to the acquisition of the items; including US Dollar, meanwhile for the Group Brazilian company the functional provisions for asset retirement obligation. currency is the local currency, which is the Brazilian Real. Oil and gas exploration and production activities are accounted for in b) Transactions and balances Foreign currency transactions are translated into the functional currency accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance using the exchange rates prevailing at the dates of the transactions. Foreign with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exchange gains and losses resulting from the settlement of such transactions exploration and evaluation costs until such time as the economic viability and from the translation at period end exchange rates of monetary assets of producing the underlying resources is determined. Costs incurred prior to and liabilities denominated in foreign currencies are recognised in the obtaining legal rights to explore are expensed immediately to the Consolidated Statement of Income. Consolidated Statement of Income. 2.6 Joint arrangements The company has applied IFRS 11 to all joint arrangements as of 1 January Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e.: seismic), direct labour costs and drilling 2013. Under IFRS 11 investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and costs of exploratory wells. No depreciation and/or amortisation are charged during the exploration and evaluation phase. Upon completion of obligations each investor. the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which The Company has assessed the nature of its joint arrangements and the determination is made depending whether they have found reserves determined them to be joint operations. The company combines its share in or not. If not developed, exploration and evaluation assets are written the joint operations individual assets, liabilities, results and cash flows on a off after three years, unless it can be clearly demonstrated that the carrying line-by-line basis with similar items in its financial statements. value of the investment is recoverable. 2.7 Revenue recognition Revenue from the sale of crude oil and gas is recognised in the Statement of A charge of US$ 30,367,000 has been recognised in the Consolidated Statement of Income within Exploration costs (US$ 10,962,000 in 2013 and Income when risk transferred to the purchaser, and if the revenue can be US$ 25,552,000 in 2012) for write-offs in Argentina, Colombia and Chile measured reliably and is expected to be received. Revenue is shown net of (see Note 11). VAT, discounts related to the sale and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent All field development costs are considered construction in progress until they a retained working interest in the property. are finished and capitalised within oil and gas properties, and are subject to depreciation once complete. Such costs may include the acquisition and 192 GeoPark 20F installation of production facilities, development drilling costs (including obligations in the period in which the wells are drilled. When the liability is dry holes, service wells and seismic surveys for development purposes), initially recorded, the Group capitalises the cost by increasing the carrying project-related engineering and the acquisition costs of rights and amount of the related long-lived asset. Over time, the liability is accreted concessions related to proved properties. to its present value at each reporting period, and the capitalized cost is Workovers of wells made to develop reserves and/or increase production interpretations and application of current legislation and on the basis of the are capitalized as development costs. Maintenance costs are charged to changes in technology and the variations in the costs of restoration necessary depreciated over the estimated useful life of the related asset. According to income when incurred. to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this Capitalised costs of proved oil and gas properties and production facilities recalculation are included in the financial statements in the period in which and machinery are depreciated on a licensed area by the licensed area basis, this recalculation is determined and reflected as an adjustment to the using the unit of production method, based on commercial proved and provision and the corresponding property, plant and equipment asset. probable reserves. The calculation of the “unit of production” depreciation takes into account estimated future finding and development costs and is based on current year end unescalated price levels. Changes in reserves 2.11.2 Deferred income Relates to contributions received in cash from the Group’s clients to improve and cost estimates are recognised prospectively. Reserves are converted to the project economics of gas wells. The amounts collected are reflected equivalent units on the basis of approximate relative energy content. as a deferred income in the balance sheet and recognised in the Consolidated Depreciation of the remaining property, plant and equipment assets depreciation of the gas wells that generated the deferred income is charged (i.e. furniture and vehicles) not directly associated with oil and gas activities to the Consolidated Statement of Income simultaneously with the has been calculated by means of the straight line method by applying amortisation of the deferred income. Statement of Income over the productive life of the associated wells. The such annual 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 Assets that are not subject to depreciation and/or amortisation Depreciation is allocated in the Consolidated Statement of Income (i.e.: exploration and evaluation assets) are tested annually for impairment. as production and administrative expenses, based on the nature of the Assets that are subject to depreciation and/or amortisation are reviewed associated asset. for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated An impairment loss is recognised for the amount by which the asset’s recoverable amount (see Impairment of non-financial assets in Note 2.12). carrying amount exceeds its recoverable amount. The recoverable amount is 2.11 Provisions and other long-term liabilities Provisions for asset retirement obligations, deferred income, restructuring 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), obligations and legal claims are recognised when the Group has a present generally a licensed area. Non-financial assets other than goodwill that legal or constructive obligation as a result of past events; it is probable suffered impairment are reviewed for possible reversal of the impairment at that an outflow of resources will be required to settle the obligation; and the each reporting date. amount has been reliably estimated. Restructuring provisions comprise lease termination penalties and employee termination payments. No asset should be kept as an exploration and evaluation asset for a period Provisions are measured at the present value of the expenditures expected carrying value of the investment will be recoverable. to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the The impairment loss recognised in 2014 is explained in Note 38; no obligation. The increase in the provision due to passage of time is recognised impairment loss has been recognised during 2013 and 2012. The write-offs as interest expense. are detailed in Note 11. of more than three years, except if it can be clearly demonstrated that the 2.11.1 Asset retirement obligation The Group records the fair value of the liability for asset retirement 2.13 Lease contracts All current lease contracts are considered to be operating leases on the basis GeoPark 20F 193 that the lessor retains substantially all the risks and rewards related to case. To the extent that actual outcomes differ from management’s estimates, the ownership of the leased asset. Payments related to operating leases and taxation charges or credits may arise in future periods. other rental agreements are recognised in the Consolidated Income Statement on a straight line basis over the term of the contract. The Group's Deferred income tax liabilities are provided on taxable temporary differences total commitment relating to operating leases and rental agreements is arising from investments in subsidiaries and joint arrangements, except disclosed in Note 31. for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the Leases in which substantially all of the risks and rewards of ownership are temporary difference will not reverse in the foreseeable future. The Group transferred to the lessee are classified as finance leases. Under a finance lease, is able to control the timing of dividends from its subsidiaries and hence does the Company as lessor has to recognize an amount receivable equal to the not expect taxable profit. Hence deferred tax is recognized in respect of the aggregate of the minimum lease payments plus any unguaranteed residual retained earnings of overseas subsidiaries only if at the date of the statements value accruing to the lessor, discounted at the interest rate implicit in the lease. of financial position, dividends have been accrued as receivable or a binding 2.14 Inventories Inventories comprise crude oil and materials. 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 these differences revert in total (e.g. dividends are declared and paid), Crude oil is measured at the lower of cost and net realisable value. Materials the deferred tax liability which the Company would have to recognize are measured at the lower of cost and recoverable amount. The cost of amounts to approximately US$ 16,000,000. materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, Deferred tax balances are provided in full, with no discounting. first-out (FIFO) method. 2.15 Current and deferred income tax The tax expense for the year comprises current and deferred tax. Tax is 2.16 Financial assets Financial assets are divided into the following categories: loans and receivables; financial assets at fair value through the profit or loss; available- recognised in the Consolidated Statement of Income. for-sale financial assets; and held-to-maturity investments. Financial assets are assigned to the different categories by management on initial The current income tax charge is calculated on the basis of the tax laws recognition, depending on the purpose for which the investments were enacted or substantially enacted at the balance sheet date in the countries acquired. The designation of financial assets is re-evaluated at every reporting where the Company’s subsidiaries operate and generate taxable income. date at which a choice of classification or accounting treatment is available. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution All financial assets are recognised when the Group becomes a party to the of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and contractual provisions of the instrument. All financial assets are initially recognised at fair value, plus transaction costs. in some cases it is difficult to predict the ultimate outcome. Deferred income tax is recognised, using the liability method, on temporary flows from the investments expire or are transferred and substantially all of differences arising between the tax bases of assets and liabilities and their the risks and rewards of ownership have been transferred. An assessment carrying amounts in the consolidated financial statements. Deferred income for impairment is undertaken at each balance sheet date. Derecognition of financial assets occurs when the rights to receive cash tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and are expected to apply Interest and other cash flows resulting from holding financial assets are when the related deferred income tax asset is realised or the deferred income recognised in the Consolidated Income Statement when receivable, tax liability is settled. regardless of how the related carrying amount of financial assets is measured. In addition, the Group has tax-loss carry-forwards in certain taxing Loans and receivables are non-derivative financial assets with fixed or jurisdictions that are available to offset against future taxable profit. However, determinable payments that are not quoted in an active market. They are deferred tax assets are recognized only to the extent that it is probable that included in current assets, except for maturities greater than twelve months taxable profit will be available against which the unused tax losses can be after the balance sheet date. These are classified as non current assets. The utilized. Management judgment is exercised in assessing whether this is the Group’s loans and receivables comprise trade receivables, prepayments and 194 GeoPark 20F other receivables and cash at bank and in hand in the balance sheet. They Direct issue costs are charged to the Consolidated Statement of Income on arise when the Group provides money, goods or services directly to a an accruals basis using the effective interest method. debtor with no intention of trading the receivables. Loans and receivables are subsequently measured at amortised cost using the effective interest method, less provision for impairment. Any change in their value through 2.22 Share capital Equity comprises the following: impairment or reversal of impairment is recognised in the Consolidated Statement of Income. All of the Group’s financial assets are classified as loan • “Share capital” representing the nominal value of equity shares. and receivables. 2.17 Other financial assets Non current other financial assets include contributions made for environmental obligations according to a Colombian government request. • “Share premium” representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issue. • “Other reserve” representing: - the equity element attributable to shares granted according to IFRS 2 This investment was intended to guarantee interest payments and was but not issued at year end or, recovered at repayment date (see Note 26). - the difference between the proceeds from the transaction with non- 2.18 Impairment of financial assets Provision against trade receivables is made when objective evidence is in the Chilean and Colombian subsidiaries (see Note 34.b). • “Translation reserve” representing the differences arising from translation received that the Group will not be able to collect all amounts due to of investments in overseas subsidiaries. it in accordance with the original terms of those receivables. The amount • “Retained earnings (accumulated losses)” representing accumulated controlling interests received against the book value of the shares acquired of the write-down is determined as the difference between the asset's earnings and losses. carrying amount and the present value of estimated future cash flows. 2.19 Cash and cash equivalents Cash and cash equivalents includes cash in hand, deposits held at call 2.23 Share-based payment The Group operates a number of equity-settled and cash-settled share-based compensation plans comprising share awards payments and stock options with banks, other short-term highly liquid investments with original plans to certain employees and other third party contractors. maturities of three months or less, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of Share-based payment transactions are measured in accordance with IFRS 2. the Consolidated Statement of Financial Position. Fair value of the stock option plan for employee or contractors services 2.20 Trade and other payables Trade payables are obligations to pay for goods or services that have been received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed over the vesting period is determined acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year by reference to the fair value of the options granted calculated using the Black-Scholes model. or less (or in the normal operating cycle of the business if longer). If not, they are presented as non current liabilities. Non-market vesting conditions are included in assumptions about the Trade payables are recognised initially at fair value and subsequently the entity revises its estimates of the number of options that are expected measured at amortised cost using the effective interest method. to vest. It recognises the impact of the revision to original estimates, number of options that are expected to vest. At each balance sheet date, if any, in the Consolidated Statement of Income, with a corresponding 2.21 Borrowings Borrowings are obligations to pay cash and are recognised when the Group adjustment to equity. becomes a party to the contractual provisions of the instrument. The fair value of the share awards payments is determined at the grant date by reference of the market value of the shares and recognised as an Borrowings are recognised initially at fair value, net of transaction expense over the vesting period. costs incurred. Borrowings are subsequently stated at amortised cost; any difference between the proceeds (net of transaction costs) and the When the options are exercised, the Company issues new shares. redemption value is recognised in the Consolidated Statement of Income The proceeds received net of any directly attributable transaction costs are over the period of the borrowings using the effective interest method. GeoPark 20F 195 credited to share capital (nominal value) and share premium when the Most of the Group's assets held in those countries are associated with oil and options are exercised. gas productive assets. Those assets, even in the local markets, are generally settled in US Dollar equivalents. For cash-settled share-based payment transactions, the Company measures the services acquired for amounts that are based on the price of During 2014, the Argentine Peso devaluated by 31% (devaluated by 33% and the Company’s shares. The fair value of the liability incurred is measured 16% in 2013 and 2012 respectively) against the US Dollar, the Chilean Peso using Geometric Brownian Motion method. Until the liability is settled, devaluated by 16% (devaluated by 10% and strengthened by 8% in 2013 and the Company is required to remeasure the fair value of the liability at each 2012 respectively) and the Colombian Peso devaluated by 24% (devaluated reporting date and at the date of settlement, with any changes in value by 9% and strengthened by 9% in 2013 and 2012 respectively). recognised in profit or loss for the period. Note 3 If the Argentine Peso, the Chilean Peso and the Colombian Peso had each devaluated an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been lower by Financial Instruments-risk management US$ 621,400 (higher by US$ 279,000 in 2013 and lower by US$ 91,000 in 2012). As of 31 December 2014, the balances denominated in the The Group is exposed through its operations to the following financial risks: Peruvian local currency (Peruvian Soles) are not material. • Currency risk. • Price risk. • Credit risk - concentration. • Funding and liquidity risk. • Interest rate risk. • Capital risk management. In Brazil the functional currency is the local currency, which is the Brazilian Real. The fluctuation of the US Dollars against the Brazilian Real does not 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 loan. Most of the balances are denominated in Brazilian Real, and since it is the functional currency of the Brazilian subsidiary, there The policy for managing these risks is set by the Board. Certain risks are is no exposure to currency fluctuation except from cash at bank held in managed centrally, while others are managed locally following guidelines US Dollars and for the Itaú loan described in Note 26. communicated from the corporate office. The policy for each of the above risks is described in more detail below. During 2014, the Brazilian Real devaluated by 13% against the US Dollar. If the Brazilian Real had devaluated an additional 10% against the US dollar, Currency risk In Argentina, Colombia, Chile and Peru the functional currency is the US with all other variables held constant, post-tax profit for the year would have been lower by US$ 5,660,000 (higher by US$ 3,652,000 in 2013). Dollar. The 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 balances denominated in local currencies. Such is As currency rate changes between the U.S. Dollar and the local currencies, the Group recognizes gains and losses in the Consolidated Statement of Income. the case of the prepaid taxes. In Chile, Colombia and Argentina subsidiaries most of the balances Price risk The price realised for the oil produced by the Group is linked to WTI (West are denominated in US Dollars, and since it is the functional currency of the Texas Intermediate) and Brent, US dollar denominated international subsidiaries, there is no exposure to currency fluctuation except from benchmarks. The market price of these commodities is subject to significant receivables or payables originated in local currency mainly corresponding to fluctuation and has historically fluctuated widely in response to relatively VAT. The balances as of 31 December 2014 of VAT were credits for minor changes in the global supply and demand for oil and natural gas, US$ 73,000 (US$ 3,177,000 in 2013) in Argentina, credits for US$ 5,107,000 market uncertainty, economic conditions and a variety of additional factors. (US$ 5,288,000 in 2013) in Chile, and payable for US$ 1,358,000 (US$ 5,870,000 in 2013) in Colombia. Between September 2014 and February 2015, WTI and Brent have fallen more than 40%, affecting both: the Company’s results in 2014 and the Company’s The Group minimises the local currency positions in Argentina, Colombia expectations for 2015 (see Note 37). and Chile by seeking to equilibrate local and foreign currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore the Group maintains a net exposure to them. 196 GeoPark 20F In Colombia, the price of oil is based on Brent, adjusted for certain marketing owned oil and gas company. In Chile, most of gas production is sold to and quality discounts based on, among other things, API, viscosity, sulphur, the local subsidiary of the Methanex, a Canadian public company (6% of delivery point and water content. consolidated revenues, 7% in 2013 and 12% in 2012). In Chile, the oil price is based on Brent minus certain marketing and quality In Brazil, all the hydrocarbons from Manatí Field are sold to Petrobras, the discounts such as, inter alia, API quality and others. In Argentina, the oil price operator of the Manatí Field and the State owned company. is also subject to the impact of the retention tax on oil exports defined by the Argentine government which limits the direct correlation to the WTI. The mentioned companies all have good credit standing and despite the concentration of the credit risk, the Directors do not consider there to The Company has signed a long-term Gas Supply Contract with Methanex in be a significant collection risk. Chile. The price of the gas sold under this contract is determined based on a formula that takes into account various international prices of methanol, See disclosure in Note 24. including US Gulf methanol spot barge prices, methanol spot Rotterdam prices and spot prices in Asia. Funding and liquidity risk In the past, the Group was able to raise capital through different sources of In Brazil, prices for gas produced in the Manatí Field are based on a long-term funding including equity, strategic partnerships and financial debt. off-take contract with Petrobras. The price of gas sold under this contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant The Group is positioned at the end of 2014 with a cash balance of to the Brazilian General Market Price Index (Indice Geral de Preços do US$ 128 million and over 80% of its total indebtedness maturing in 2020. Mercado), or IGPM. In addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over If the market prices of WTI, Brent and methanol had fallen by 10% compared 20,000 boepd in production. This scale and positioning permit to actual prices during the year, with all other variables held constant, GeoPark to protect its financial condition and selectively allocate capital post-tax profit for the year would have been lower by US$ 29,186,000 (lower to the optimal projects subject to prevailing macroeconomic conditions. by US$ 27,179,000 in 2013 and US$ 18,784,000 in 2012). The Group has no price-hedging transaction currently outstanding. The Board could consider adopting commodity price hedging measures, when On February 2014, the Group received a gross proceed of US$ 98 million from deemed appropriate, according to the size of the business, production levels the issuance of new shares (see Note 1). The most significant funding transactions executed in 2014 and 2013 include: and market implied volatility. Credit risk - concentration The Group’s credit risk relates mainly to accounts receivable where the credit International (Itau) for US$ 70.5 million to finance the acquisition of a working interest in the Manatí field (Brazil) (see Note 34.c) maturing between 2015 On March 2014, GeoPark executed a loan agreement with Itaú BBA risks correspond to the recognised values. There is not considered to be any and 2019. significant risk in respect of the Group’s major customers. In Colombia, the Group have diversified the customer base and for the These notes contain customary incurrence covenants, which include, year ended 31 December 2014, the Colombian subsidiary made 40.1% of among others, limitations on the incurrence of additional debt (see Note 26). On February 2013 the Group placed US$ 300 million notes maturing in 2020. the oil sales to Gunvor (a global privately-held company, dedicated to commodities trading), 31.8% to Emerald (a UK based company engaged in the exploration and production of hydrocarbons) and 11% to Perenco Interest rate risk The Group’s profit and operating cash flows are substantially independent (a global independent company, dedicated to oil and gas production), of changes in market interest rates. The Group’s interest rate risk arises from with Gunvor accounting for 23%, Emerald 18.3% and Perenco 6.3% long-term borrowings issued at variable rates, which expose the Group to of consolidated revenues for the same period. cash flow to interest rate risk. All the oil produced in Chile is sold to ENAP as well as the gas produced by The Group does not face interest rate risk on its US$ 300,000,000 Notes which TdF Blocks (28% of total revenue, 40% in 2013 and 48% in 2012), the State carry a fixed rate coupon of 7.50% per annum. GeoPark 20F 197 At 31 December 2014 the outstanding long-term borrowing affected by Note 4 variable rates amounted to US$ 68,540,000, representing 19% of total Accounting estimates and assumptions long-term borrowings, which was composed by the loan from Itaú Bank that has a floating interest rate based on LIBOR. Estimates and assumptions are used in preparing the financial statements. Although these estimates are based on management's best knowledge The Group analyses its interest rate exposure on a dynamic basis. Various of current events and actions, actual results may differ from them. Estimates scenarios are simulated taking into consideration refinancing, renewal of and judgements are continually evaluated and are based on historical existing positions, alternative financing and hedging. Based on these experience and other factors, including expectations of future events that are scenarios, the Group calculates the impact on profit and loss of a defined believed to be reasonable under the circumstances. interest rate shift. For each simulation, the same interest rate shift is used for all currencies. The scenarios are run only for liabilities that represent the The key estimates and assumptions used in these consolidated financial major interest-bearing positions. statements are noted below: At 31 December 2014, if 1% is added to interest rates on currency- • The Group adopts the successful efforts method of accounting. The denominated borrowings with all other variables held constant, post-tax Management of the Company makes assessments and estimates regarding profit for the year would have been US$ 312,000 lower (nil in 2013 and whether an exploration asset should continue to be carried forward as US$ 160,866 lower in 2012). Capital risk management The Group’s objectives when managing capital are to safeguard the Group’s an exploration and evaluation asset not yet determined or when insufficient information exists for this type of cost to remain as an asset. In making this assessment the Management takes professional advice from qualified experts. ability to continue as a going concern in order to provide returns for • Cash flow estimates for impairment assessments require assumptions shareholders and benefits for other stakeholders and to maintain an optimal about two primary elements - future prices and reserves. Estimates of future capital structure to reduce the cost of capital. prices require significant judgments about highly uncertain future events. Consistent with others in the industry, the Group monitors capital on the forecasts for oil and gas revenues are based on prices derived from future basis of the gearing ratio. This ratio is calculated as net debt divided by total price forecasts amongst industry analysts and our own assessments. capital. Net debt is calculated as total borrowings (including ‘current and Our estimates of future cash flows are generally based on our assumptions non current borrowings’ as shown in the consolidated balance sheet) less of long-term prices and operating and development costs. Historically, oil and gas prices have exhibited significant volatility. Our cash at bank and in hand. Total capital is calculated as ‘equity’ as shown in the consolidated balance sheet plus net debt. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessment of impairment to be The Group’s strategy is to keep the gearing ratio within a 30% to 45% range. a critical accounting estimate (see Notes 37 and 38). The gearing ratios at 31 December 2014 and 2013 were as follows: The process of estimating reserves is complex. It requires significant Amounts in US$ '000 Net debt Total equity Total capital Gearing ratio judgements and decisions based on available geological, geophysical, 2014 241,921 479,126 721,047 34% 2013 265,952(a) 365,957 engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of 31 December 2014 prepared by DeGolyer 631,909 and MacNaughton, an international consultancy to the oil and gas industry 42% based in Dallas. It incorporates many factors and assumptions including: (a) For the calculation of the gearing ratio the Group does not consider the - expected reservoir characteristics based on geological, geophysical and cash that has been allocated for future M&A activities. In 2013, the Group has allocated US$ 70 million for the acquisition of Río Das Contas (see Note 34.c). engineering assessments; - future production rates based on historical performance and expected future operating and investment activities; - future oil and gas prices and quality differentials; - assumed effects of regulation by governmental agencies; and - future development and operating costs. 198 GeoPark 20F Management believes these factors and assumptions are reasonable based The following chart describes non-cash transactions related to the on the information available to them at the time of preparing the estimates. Consolidated Statement of Cash Flow: However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes Amounts in US$ '000 2014 2013 2012 available and as economic conditions impacting oil and gas prices and Increase in asset retirement costs change. obligation (Note 27) Financial leases (Note 19) • Oil and gas assets held in property plant and equipment are mainly Increase in provisions for other depreciated on a unit of production basis at a rate calculated by reference to long-term liabilities (Note 27) proven and probable reserves and incorporating the estimated future cost Purchase of property, plant 1,603 - 5,636 7,183 14,133 - 3,440 - - of developing and extracting those reserves. Future development costs are and equipment 1,382 12,799 2,375 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 • Obligations related to the plugging of wells once operations are terminated to the purchase and sale of enterprises to third parties and cash flows may result in the recognition of significant obligations. Estimating the future from financial lease transactions. Cash flows from financing activities include abandonment costs is difficult and requires management to make estimates changes in Shareholders’ equity, and proceeds from borrowings and and judgments because most of the obligations are many years in the repayment of loans. Cash and cash equivalents include bank overdraft and 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 abandonment related costs: The present value of future costs necessary Flow are disclosed as follows: for 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 Increase in prepaid taxes estimated future abandonment costs, wells subject to abandonment, time (Increase)/decrease in inventories to abandonment, and future inflation rates. Decrease/(increase) in trade receivables 2014 (3,310) (410) 2013 (4,283) (4,166) 2012 (11,046) 8,837 13,791 (10,357) (7,842) • From time to time, the Company may be subject to various lawsuits, Decrease/(increase) in prepayments claims and proceedings that arise in the normal course of business, including and other receivables and other assets 12,569 (13,330) 7,384 employment, commercial, environmental, safety and health matters. For (Decrease)/increase in trade and example, from time to time, the Company receives notice of environmental, health and safety violations. Based on what the Management of the other payables (9,293) 13,347 36 (32,100) 6,070 3,403 Company currently knows, it is not expected any material impact on the financial statements. Note 5 Note 6 Segment information Consolidated Statement of Cash Flow Management has determined the operating segments based on the reports reviewed by the strategic steering committee that are used to make The Consolidated Statement of Cash Flow shows the Group's cash flows strategic decisions. The committee considers the business from a geographic for the year for operating, investing and financing activities and the change perspective. in cash and cash equivalents during the year. Cash flows from operating activities are computed from the results for the segments based on a measure of adjusted earnings before interest, tax, year adjusted for non-cash operating items, changes in net working capital, depreciation, amortisation and certain non-cash items such as write-offs, and corporation tax. Tax paid is presented as a separate item under impairments and share-based payment (Adjusted EBITDA). This measurement operating activities. basis excludes the effects of non-recurring expenditure from the operating The strategic steering committee assesses the performance of the operating GeoPark 20F 199 segments, such as impairments when it is the result of an isolated, non- expenses included in Administrative, Exploration and Other operating costs. recurring event. Interest income and expenses are not included in the result Other information provided, except as noted below, to the strategic steering for each operating segment that is reviewed by the strategic steering committee is measured in a manner consistent with that in the financial committee. Operating Netback is equivalent to Adjusted EBITDA before cash statements. Segment areas (geographical segments): Amounts in US$ '000 Argentina Brazil Colombia Peru Chile Corporate Total 1,308 1,304 4 (644) (94) (241) (87) (222) 664 (4,321) (816) (229) - (31) 3,839 100 1,538 1,532 6 (346) (59) (194) (204) 111 1,192 (1,942) 166 (225) - 7,977 97 35,621 1,541 34,080 (19,702) (11,554) (2,794) - (5,354) 15,919 10,658 22,637 (11,613) - - 151,770 10 - - - - - - - - - (3,107) (3,037) (2) - 29,222 3 246,085 246,054 31 (131,680) (51,856) (12,354) (4,663) (62,807) 114,405 67,212 130,209 (52,713) (9,430) (1,564) 263,070 121 179,324 179,324 - (111,712) (39,233) (9,661) (4,733) (58,085) 67,612 38,811 82,611 (39,406) (3,258) 259,421 107 - - - - - - - - - (2,419) (2,425) - - - 4,813 4 - - - - - - - - - - - - - - - 145,720 118,203 27,517 (77,624) (35,856) (6,777) (6,784) (28,207) 68,096 11,733 76,420 (37,077) - (28,772) 541,481 208 157,491 134,579 22,912 (67,585) (29,287) (7,384) (6,455) (24,459) 89,906 63,110 96,348 (30,471) (7,704) 477,263 184 - - - - - - - - - (11,019) (5,948) (25) - - 428,734 367,102 61,632 (229,650) (99,360) (22,166) (11,534) (96,590) 199,084 71,844 220,077 (101,657) (9,430) (30,367) 74,143 1,039,116 - - - - - - - - - - (12,908) (8,835) (96) - 72,532 - 443 338,353 315,435 22,918 (179,643) (68,579) (17,239) (11,392) (82,433) 158,710 83,964 167,253 (70,200) (10,962) 846,415 391 2014 Net revenue - Sale of crude oil - Sale of gas Production costs - Depreciation - Royalties - Transportation costs - Other costs - Gross profit Operating (loss)/profit Adjusted EBITDA Depreciation Impairment loss Write-off Total assets Employees (average) 2013 Net revenue - Sale of crude oil - Sale of gas Production costs - Depreciation - Royalties - Transportation costs - Other costs Gross profit Operating (loss)/profit Adjusted EBITDA Depreciation Write-off Total assets Employees (average) 200 GeoPark 20F Amounts in US$ '000 Argentina Brazil Colombia Peru Chile Corporate Total 2012 Net revenue - Sale of crude oil - Sale of gas Production costs - Depreciation - Royalties - Transportation costs - Other costs Gross (loss)/profit Operating (loss)/profit Adjusted EBITDA Depreciation Write-off Total assets Employees (average) 1,050 1,045 5 (3,244) (3,223) (172) (180) 331 (2,194) (6,129) 2,051 (3,408) (1,915) 6,108 100 - - - - - - - - - - - - - - - 99,501 99,501 - (60,197) (20,964) (4,165) (1,045) (34,023) 39,304 8,500 34,474 (21,050) (5,147) 213,202 80 - - - - - - - - - - - - - - - 149,927 121,018 28,909 (65,794) (28,120) (7,087) (5,986) (24,601) 84,133 47,915 93,908 (28,734) (18,490) 405,674 144 - - - - - - - - - (9,539) (9,029) (125) - 3,033 - 250,478 221,564 28,914 (129,235) (52,307) (11,424) (7,211) (58,293) 121,243 40,747 121,404 (53,317) (25,552) 628,017 324 Approximately 66% of capital expenditure was allocated to Chile (63% in 2013 and 70% in 2012), 29% was allocated to Colombia (37% in 2013 and 30% in 2012) and 5% was allocated to Brazil (nil in 2013 and 2012). The capital expenditure referred does not include total consideration for M&A activities. A reconciliation of total Operating netback to total profit before income tax is provided as follows: Amounts in US$ '000 Operating netback Administrative costs(a) Exploration costs(b) Adjusted EBITDA for reportable segments Depreciation(c) Share-based payment Impairment and write-off of unsuccessful efforts Others(d) Operating profit Financial results Bargain purchase gain on acquisition of subsidiaries Profit before tax 2014 274,509 (40,340) (14,092) 2013 214,683 (39,573) (7,857) 220,077 (100,528) 167,253 (69,968) (8,373) (9,167) 2012 151,270 (25,507) (4,359) 121,404 (56,448) (5,396) (39,797) (10,962) (25,552) 465 71,844 (50,719) 6,808 83,964 (33,876) 6,739 40,747 (16,308) - - 21,125 50,088 8,401 32,840 (a) Excludes depreciation and share-based payment. (b) Includes staff costs and other services. (c) Net of capitalised costs for oil stock included in Inventories. (d) Includes internally capitalised costs. GeoPark 20F 201 Note 9 Depreciation 2014 2013 2012 Amounts in US$ '000 367,102 315,435 221,564 Oil and gas properties 61,632 22,918 28,914 Production facilities and machinery 428,734 338,353 250,478 Furniture, equipment and vehicles Buildings and improvements Depreciation of property, 2014 89,651 9,621 1,862 523 2013 59,234 9,341 964 661 2012 44,552 7,708 713 344 plant and equipment 101,657 70,200 53,317 Recognised as follows: 2012 Production costs 52,307 Administrative costs 9,385 Depreciation total 11,424 9,884 12,384 Note 10 99,360 2,297 101,657 68,579 1,621 70,200 52,307 1,010 53,317 2014 99,360 25,475 22,166 16,157 16,112 1,619 11,534 7,563 9,730 5,733 5,932 3,277 - 4,992 2013 68,579 20,662 17,239 14,855 11,650 2,552 11,392 7,139 5,635 4,843 4,805 3,217 - 7,075 Staff costs and Directors Remuneration 1,787 7,211 5,936 1,030 1,428 2,407 3,371 3,826 6,855 Average number of employees Amounts in US$ '000 Wages and salaries Share-based payment (Note 29) Share-based payment - Cash awards (Note 29) Social security charges Director’s fees and allowance 229,650 179,643 129,235 Recognised as follows: Production costs Exploration costs Administrative costs Board of Directors’ and key managers’ remuneration(1) Salaries and fees Share-based payment Other benefits 2014 443 2013 391 2012 324 41,593 9,178 29,504 8,362 19,132 5,396 (805) 6,597 1,998 805 5,291 1,426 - 3,636 1,516 58,561 45,388 29,680 17,731 12,939 27,891 58,561 14,202 7,676 23,510 45,388 14,171 4,418 11,091 29,680 11,003 3,314 130 7,702 2,971 742 5,711 846 - 14,447 11,415 6,557 (1) All the figures are included in the Staff costs and Directors Remuneration table. Note 7 Net Revenue Amounts in US$ '000 Sale of crude oil Sale of gas Note 8 Production costs Amounts in US$ '000 Depreciation Well and facilities maintenance Royalties Consumables Staff costs (Note 10) Share-based payment (Notes 10 and 29) Transportation costs Equipment rental Non operated blocks costs Safety and Insurance costs Field camp Gas plant costs Cost of crude oil sold from acquired business Other costs 202 GeoPark 20F 202 GeoPark 20F Directors’ Remuneration Gerald O’Shaughnessy James F. Park Pedro Aylwin2 Peter Ryalls3 Juan Cristóbal Pavez4 Carlos Gulisano5 Steven J. Quamme6 Executive directors’ fees US$ 250,000 US$ 500,000 Executive directors’ bonus US$ 150,000 US$ 650,000 - - - - - - - - - - Non-executive Non-executive Director fees Cash equivalent directors’ fees directors’ fees (in £) (in US$) - - - £ 8,750 £ 11,625 £ 20,375 £ 11,625 - - US$ 57,500 US$ 55,000 US$ 55,000 US$ 55,000 paid in shares No. of shares1 - - - 7,003 7,003 5,250 7,003 total remuneration US$ 400,000 US$ 1,150,000 - US$ 195,091 US$ 195,036 US$ 195,043 US$ 195,036 1 Only 2,301 shares of the 26,259 shares paid as Director Fees were issued during 2014 (see Note 29). 2 Pedro Aylwin has a service contract that provides for him to act as Manager of Legal and Governance so he resigned his fees as Director. 3 Technical Committee Chairman. 4 Compensation Committee Chairman. 5 Nomination Committee Chairman. 6 Audit Committee Chairman. From the second half of 2014, an increase in the compensation program for the services of the non-executive Directors was approved. The 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 USD 20,000 shall apply. A Director who serves as a member of any Board Committees shall receive an annual fee of USD 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. GeoPark 20F 203 GeoPark 20F 203 IPO Stock Options to Executive Directors The following Stock Options were issued to Executive Directors during 2006: Note 11 Exploration costs N° of underlying common shares Exercise price (£) Earliest exercise date Amounts in US$ '000 Write-off of unsuccessful efforts(a) Staff costs (Note 10) Expiry date Other services Name Gerald O’Shaughnessy 153,345 306,690 James F. Park 153,345 306,690 3.20 4.00 3.20 4.00 15 May 15 May Allocation to capitalised project 2008 2013 Share-based payment (Notes 10 and 29) 15 May 15 May Amortisation of other long-term 2008 2013 liabilities related to unsuccessful efforts 15 May 15 May Recovery of abandonments costs 2008 2013 15 May 15 May 2014 30,367 11,712 2,380 (2,317) 1,227 - - 2013 10,962 6,451 1,406 (2,437) 1,225 (600) (753) 2012 25,552 3,090 1,269 (1,849) 1,328 (1,500) - 43,369 16,254 27,890 During 2013 the abovementioned stock options were fully exercised by the two in Tranquilo Block and one in Campanario Block) and two of them in 2008 2013 (a) The 2014 charge corresponds to the cost of ten unsuccessful exploratory wells: eight of them in Chile (three in Flamenco Block, two in Fell Block, Executive Directors. Stock Awards to Executive Directors The following Stock Options were issued to Executive Directors during 2012: Colombia (two in the non-operated Arrendajo Block, see Note 34). The 2014 charge also includes the loss generated by the write-off of the remaining seismic cost for Otway and Tranquilo Blocks, registered in previous years. The 2013 charge corresponds to the cost of five unsuccessful exploratory wells: two of them in Chile (one in Fell Block and one in Tranquilo Block) and N° of underlying common shares Name Gerald O’Shaughnessy 270,000 James F. Park 450,000 Grant date 23 Nov 2012 23 Nov 2012 Exercise Earliest three of them in Colombia (one well in Cuerva Block, one well in each of price (US$) exercise the non-operated blocks, Arrendajo and Llanos 32). date 23 Nov The 2012 charge corresponds to the costs of eight unsuccessful exploratory 0.001 2015 wells: five of them in Chile (two in Fell Block, two in Otway Block and 23 Nov the remaining in Tranquilo Block) and three of them in Colombia (one well 0.001 2015 in Cuerva Block, one well in Arrendajo Block and the remaining in Llanos 17 Block). The 2012 charge also includes the loss generated by the relinquishment of an area in the Del Mosquito Block in Argentina. In addition, Dr Carlos Gulisano holds the following interests in stock options and awards as a result of the services that he has previously provided to the Company: • 50,000 IPO Stock Options issued on 15 May 2008 at an exercise price of £ 4.00 to be exercised between 15 May 2008 and 15 May 2013. These were fully exercised during 2013. • 100,000 Stock awards issued on 15 December 2008 at an exercise price of $0.001 to be exercised between 15 December 2012 and 15 December 2018. In addition, Pedro Aylwin holds the following interests in stock options and awards as a result of the services that he has previously provided to the Company: • 156,431 shares fully exercised. • 12,000 stock awards related to the 2011 Programme not yet vested. 204 GeoPark 20F 204 GeoPark 20F Note 12 Administrative costs Amounts in US$ '000 Staff costs (Note 10) Share-based payment (Notes 10 and 29) Consultant fees New projects Office expenses Director’s fees and allowance Travel expenses Depreciation Other administrative expenses 2014 20,366 2013 16,694 5,527 6,791 2,798 3,190 1,998 2,052 2,297 3,145 5,390 6,424 3,720 2,652 1,426 1,258 1,621 7,399 2012 7,294 2,281 5,122 2,927 3,293 1,516 1,563 1,010 3,792 Note 15 Tax reforms in Colombia and Chile Colombia The Colombian Congress approved a Tax Reform in December 2014. This reform has 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 (Enterprise contribution on equality, “CREE” for its Spanish acronym) at 9%, and applied a CREE surcharge until 2018, among other changes. The net wealth tax (NWT) assessed on net equity would apply for tax years 2015 through 2017 for domestic and foreign entities that hold any wealth in Colombia, directly or indirectly, via permanent establishments (PEs) Note 13 Selling expenses Amounts in US$ '000 Transportation Selling taxes Storage Allowance for doubtful accounts Delivery or pay penalty Note 14 Financial results Amounts in US$ '000 Financial expenses Interest and amortisation of debt issue costs Less: amounts capitalised on qualifying assets Exchange difference(1) Bank charges and other financial costs Unwinding of long-term liabilities Notes GeoPark Fell SpA cancellation costs (Note 26) Financial income Interest received 48,164 46,584 28,798 or branches. In the case of foreign or domestic individuals, the NWT would apply until 2018. NWT would apply at progressive rates ranging from 1.15% in 2014; 1% in 2015 and decrease to 0.4% in 2016 and finally disappear in 2017, for corporate taxpayers. NWT paid would not be deductible or creditable for 2012 Colombian income tax purposes. 22,066 202 645 The Reform also extended the current 9% CREE tax rate, which was scheduled to decrease to 8% in 2016. Also, it will introduce a new CREE surcharge, - beginning in 2015, from 5% in 2015, 6% in 2016, and 8% in 2017 to 9% in 1,718 2018. Therefore, the accumulated corporate income tax rate will raise 2014 23,106 2013 16,181 433 148 741 - 406 665 - - 24,428 17,252 24,631 to 43% in 2018. The Company has considered the effects of this rate increase in the deferred income tax calculation. 2014 2013 2012 Chile The Chilean Congress approved a reform to the income tax law in September 2014. Under this reform the income tax rate will increase from 20% in 2013 according to this schedule: 21% in 2014, 22.5% in 2015, 24% in 2016, 25.5% in 2017 and 27% in 2018. 29,466 25,209 13,114 The operating subsidiaries that GeoPark controls in Chile, which are GeoPark (3,112) 23,097 (1,313) 760 (1,369) affected by the income tax reform mentioned since they are covered by the 2,081 tax treatment established in the Special contract of operations (“CEOPs”). TdF S.A., GeoPark Fell SpA and GeoPark Magallanes Limitada, are not 2,672 1,972 2,519 1,523 1,764 1,262 - 8,603 - (3,376) 50,719 (3,425) 33,876 (544) 16,308 (1) Includes in 2014, US$ 19,163,000 generated by borrowings in US Dollars held by the Brazilian subsidiary. GeoPark 20F 205 GeoPark 20F 205 Note 16 Income tax Amounts in US$ '000 Current tax Deferred income tax (Note 17) The Group has significant tax losses available which can be utilised against future taxable profit in the following countries: 2014 23,574 (18,379) 5,195 2013 13,337 1,817 15,154 2012 7,536 6,858 14,394 Amounts in US$ '000 Argentina Chile(1) Brazil(1) Total tax losses at 31 December 2014 6,707 33,222 3,191 43,120 2013 10,259 15,935 - 2012 11,645 4,380 - 26,194 16,025 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 (1) Taxable losses have no expiration date. of the consolidated entities as follows: Amounts in US$ '000 Profit before tax Tax losses from non-taxable jurisdictions Taxable profit Income tax calculated at domestic tax rates applicable to profits in the respective countries 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) Non-taxable results(1) Income tax 2014 21,125 2013 50,088 5,010 26,135 14,348 64,436 At the balance sheet date deferred tax assets in respect of tax losses in 2012 Argentina have not been recognised as there is insufficient evidence of future 32,840 taxable profits before the statute of limitation of these tax losses causes them to expire. 8,373 41,213 Expiring dates for tax losses accumulated at 31 December 2014 are: 7,606 14,011 6,290 148 328 2,864 Expiring date 2015 2016 2017 Amounts in US$ '000 3,222 1,503 1,982 (8,128) - (5,146) 1,988 691 4,878 5,195 - 3,973 2,436 - - Note 17 Deferred income tax 2,804 The gross movement on the deferred income tax account is as follows: 15,154 14,394 Amounts in US$ '000 2014 (9,729) (3,132) (2,123) (265) 18,379 3,130 2013 (3,911) - (4,001) - (1,817) (9,729) 2012 (12,659) 15,606 - - (6,858) (3,911) (1) Includes non-deductible expenses in each jurisdiction and changes in the Deferred tax at 1 January estimation of deferred tax assets and liabilities. Under current Bermuda law, the Company is not required to pay any taxes Acquisition of subsidiaries Reclassification(1) Currency translation differences in Bermuda on income or capital gains. The Company has received an Income statement credit/(charge) undertaking from the Minister of Finance in Bermuda that, in the event of Deferred tax at 31 December any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Income tax rates in those countries where the Group operates (Argentina, Brazil, Colombia, Peru and Chile) ranges from 15% to 35%. 206 GeoPark 20F 206 GeoPark 20F The breakdown and movement of deferred tax assets and liabilities as of 31 December 2014, 2013 and 2012 are as follows: Amounts in US$ '000 of year subsidiaries differences to net profit At end of year At the beginning Acquisition of Currency translation (Charged)/credited Deferred tax assets Difference in depreciation rates and other Taxable losses Total 2014 Total 2013 Total 2012 Amounts in US$ '000 Deferred tax liabilities Difference in depreciation rates and other Taxable losses Total 2014 Total 2013 Total 2012 (2,577) 15,935 13,358 13,591 450 - - - - 15,606 - (423) (423) - - 4,011 16,249 20,260 (233) (2,465) 1,434 31,761 33,195 13,358 13,591 At the beginning Acquisition of (Charged)/credited Currency translation of year subsidiaries to net profit Reclassification(1) differences At end of year (23,087) - (23,087) (17,502) (13,109) (3,132) - (3,132) - - (6,533) 4,652 (1,881) (1,584) (4,393) (2,123) - (2,123) (4,001) - 158 - 158 - - (34,717) 4,652 (30,065) (23,087) (17,502) (1) Corresponds to the difference between income tax provision and the final tax return presented. Note 18 Earnings per share Amounts in US$ '000 Numerator: Profit for the year Denominator: Weighted average number of shares used in basic EPS Earnings after tax per share (US$) - basic Amounts in US$ '000 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$) - diluted 2014 2013 2012 7,512 22,012 11,879 56,396,812 43,603,846 42,673,981 0.13 0.50 0.28 2014 2013 2012 56,396,812 43,603,846 42,673,981 2,443,600 2,928,203 1,435,324 58,840,412 46,532,049 44,109,305 0.13 0.47 0.27 GeoPark 20F 207 GeoPark 20F 207 Note 19 Property, plant and equipment Amount in US$ '000 Cost at 1 January 2012 Additions Disposals Write-off/Impairment loss Acquisition of subsidiaries Transfers Cost at 31 December 2012 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 Depreciation and write-down at 1 January 2012 Depreciation Depreciation and write-down at 31 December 2012 Depreciation Depreciation and write-down at 31 December 2013 Depreciation Disposals Currency translation differences Depreciation and write-down Furniture, Production Buildings Oil & gas equipment facilities and and Construction in properties and vehicles machinery improvements 171,956 4,071 (416) - 62,449 106,311 344,371 9,367 (553) - 140,075 493,260 3,013 112,646 (21,941) - (9,430) 172,399 749,947 (53,604) (44,552) (98,156) (59,234) (157,390) (89,651) - 6,602 2,175 637 - - 389 375 3,576 2,060 (22) - 117 5,731 3,367 201 (122) (353) - 3,233 12,057 (1,123) (713) (1,836) (964) (2,800) (1,862) 278 (65) 47,102 32,335 (130) - 10,865 (3,223) 86,949 512 (15,870)(*) - 27,246 98,837 11 - - (666) - 13,464 111,646 (18,628) (7,708) (26,336) (9,341) (35,677) (9,621) 151 - 2,437 - - - - 761 3,198 - - - 3,820 7,018 490 - - - - (716) (344) (1,060) (661) (1,721) (523) - - progress 32,896 81,241 - - 9,452 (69,564) 54,025 89,976 - - (103,572) 40,429 136,232 - - - - Exploration and evaluation assets(1) 42,140 83,360 - (25,552) 27,818 (34,660) 93,106 133,301 - (10,962) (67,686) 147,759 97,919 - (988) - (30,367) (73,879) Total 298,706 201,644 (546) (25,552) 110,973 - 585,225 235,216 (16,445) (10,962) - 793,034 241,032 112,847 (23,051) (1,019) (39,797) - 140,444 1,083,046 - - - - - - - - - (74,071) (53,317) (127,388) (70,200) (197,588) (101,657) 429 6,537 (292,279) - - - - - - - - - 2,019 9,527 (117,236) 59,425 at 31 December 2014 (240,439) (4,449) (45,147) (2,244) 246,215 1,740 60,613 2,138 54,025 93,106 457,837 335,870 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 Carrying amount at 31 December 2012 Carrying amount at 31 December 2013 Carrying amount at 31 December 2014 208 GeoPark 20F 208 GeoPark 20F As of 31 December 2014, the Group has pledged, as security for a mortgage Amounts in US$ '000 obtained for the acquisition of the operating base in Chile, assets amounting to US$ 482,000 (US$ 493,000 in 2013 and US$ 692,000 in 2012). Exploration wells at 31 December 2011 Additions See Note 26 (c). Write-offs Transfers (*) During 2013, the Company entered into a finance lease for which it has Acquisition of subsidiaries transferred a substantial portion of the risk and rewards of some assets which had a book value of US$ 14,100,000. As of 31 December 2013, prepayments Exploration wells at 31 December 2012 Additions and other receivables include receivables under finance leases amounting to Write-offs US$ 8,000,000, which US$ 6,500,000 are maturity no later than one year and Transfers US$ 1,500,000 between one and five years. In 2014, the finance lease finalized when the purchase option on the assets subject to the agreement was Exploration wells at 31 December 2013 Additions exercised by the lessee. Write-offs Transfers (1) Exploration wells movement and balances are shown in the table Exploration wells at 31 December 2014 below; seismic and other exploratory assets amount to US$ 99,939,000 Total 22,241 47,891 (21,339) (23,496) 1,868 27,165 77,933 (7,934) (67,246) 29,918 87,741 (24,339) (52,815) 40,505 (US$ 117,841,000 in 2013 and US$ 65,941,000 in 2012). As of 31 December 2014, there were two exploratory wells that have been capitalised for a period over a year amounting to US$ 4,657,000 and ten exploratory wells that have been capitalised for a period less than a year amounting to US$ 35,848,000. GeoPark 20F 209 GeoPark 20F 209 Note 20 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of 31 December 2014: 100% GeoPark Latin America Limited – Bermuda (Bermuda) 100% GeoPark Latin America Limited Agencia en Chile (Chile) GeoPark Limited (Bermuda) 100% 1% 99.9% 99.9% 99.9% GeoPark Argentina Limited – Bermuda (Bermuda) GeoPark Latin America Coöperatie U.A. (Netherlands) GeoPark Peru Coöperatie U.A. (Netherlands) GeoPark Brazil Coöperatie U.A. (Netherlands) 100% 80% GeoPark Argentina Limited - Argentinean Branch GeoPark Colombia Coöperatie U.A. (Netherlands) 20% LG International* 100% GeoPark Colombia SAS (Colombia) 99.9% GeoPark Brazil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) 100% Rio das Contas Produtora de Petróleo Ltda (Brazil) 80% 99.9% 100% LG International* 20% GeoPark Chile S.A. (Chile) GeoPark S.A. (Chile) GeoPark Colombia S.A. (Chile) 99.9% GeoPark SAC (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. During 2013 and 2014, with the purpose of conducting its multilocation activities and for allowing future business structures, the Company has incorporated certain wholly owned subsidiaries, that are dormant companies at the date of the issuance of these financial statements. 210 GeoPark 20F 210 GeoPark 20F Details of the subsidiaries and joint operations of the Company are set out below: Subsidiaries Joint operations Name and registered office 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) Rio das Contas Produtora de Petróleo 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 Perú Coöperatie U.A. (The Netherlands) GeoPark Brazil Coöperatie U.A. (The Netherlands) Tranquilo Block (Chile) Otway 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) Manatí Field (Brazil) Ownership interest 100% 100%(a)(k) 100%(g) 100%(a)(g) 100%(a)(b) 100%(a) 100%(a)(j) 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%(m)(a) 100%(m)(a) 100%(m)(a) 100%(m) 100% 29%(i)(f) 100%(e)(f) 50%(f) 50%(f) 60%(f) 36.84%(l) 75%/54.5%(f) (l) 45%(f)(l) 10%(l) 50%(l) 18% 18% 10%(j) (a) Indirectly owned. (b) Dormant companies. (c) LG International has 20% interest. (h) During 2013, the Company finalized a merger process by which GeoPark Colombia SAS continued the operations related to GeoPark Luna SAS (Colombia), GeoPark Llanos SAS (Colombia), La Luna Oil Co. Ltd. (Panama), (d) LG International has 20% interest through GeoPark Chile S.A. and a 14% Winchester Oil and Gas S.A. (Panama), GeoPark Cuerva LLC (United States), direct interest, totalling 31.2%. Sucursal La Luna Oil Co. Ltd. (Colombia), Sucursal Winchester Oil and Gas S.A. (e) In September 2014, the Chilean Ministry of Energy approved that the (Colombia) and Sucursal GeoPark Cuerva LLC (Colombia). Group will be the sole participant with a working interest of 100%. (i) At 31 December 2013, the Consortium members and interest were: (f) GeoPark is the operator in all blocks. (g) Formerly named GeoPark Chile Limited. GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. During 2014, Methanex and Wintershall announced their decision to abandon the GeoPark 20F 211 GeoPark 20F 211 Consortium. The new ownership is GeoPark 50% and Pluspetrol 50%. Note 23 (j) On 17 December 2014, the ANP approved the transfer of cession of Trade receivables and Prepayments and other receivables 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 Amounts in US$ '000 GeoPark Brazil (see Note 34.c). Trade accounts receivable (k) In April 2014, the Company informed the Secretary of Infrastructure and Energy of the province of Mendoza of its decision to relinquish 100% To be recovered from co-venturers of the Cerro Doña Juana and Loma Cortaderal Concessions to the Prepayments and other receivables 2014 36,917 36,917 5,931 8,411 14,342 51,259 2013 42,628 42,628 15,508 26,617 42,125 84,753 50,910 349 51,259 78,392 6,361 84,753 Total Classified as follows: Current Non current Total 2014 8,884 4,834 994 2013 Trade receivables that are aged by less than three months are not 10,635 considered impaired. As of 31 December 2014, trade receivables of US$ 6,092 4,945 2,853 (US$ 1,143,393 in 2013) were aged by more than 3 months, but not impaired. These relate to customers for whom there is no recent history of default. 14,712 18,433 There are no balances due between 31 days and 90 days as of 31 December 13,459 1,253 14,712 2014 6,719 1,813 8,532 2014 and 2013. 6,979 11,454 Movements on the Group provision for impairment are as follows: 18,433 Amounts in US$ '000 At 1 January Allowance for doubtful accounts (Note 13) 2014 33 741 774 2013 33 - 33 2013 4,464 3,658 The credit period for trade receivables is 30 days. The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable. The Group does not hold any collateral as security related to trade 8,122 receivables. The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature. Mendoza Province. (l) See Note 34.a. (m) See Note 34.d. 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 212 GeoPark 20F 212 GeoPark 20F Note 24 Financial instruments by category Cash at bank and other financial assets(1) Amounts in US$ '000 Assets as per statement of financial position Trade receivables To be recovered from co-venturers Other financial assets (*) Cash at bank and in hand Amounts in US$ '000 2014 2013 Loans and receivables Counterparties with an external credit rating 2014 2013 (Moody’s, S&P, Fitch, BRC Investor Services) 36,917 5,931 12,979 42,628 15,508 5,168 127,672 121,135 183,499 184,439 A1 A2 Aa3 P1 P2 P3 AA+ BRC 1+ 17 22,621 - 40,402 42,218 21,145 - 994 4,812 - 11 102,390 460 3,789 2,643 3,546 8,631 (*) Other financial assets relate to contributions made for environmental obligations according to Colombian and Brazilian government regulations. Counterparties without an external credit rating 13,142 For 2014, they also include a non current account receivable. Total 140,539 126,282 Other financial liabilities hand amounting to US$ 112,000 (US$ 21,000 in 2013). (1) The rest of the balance sheet item ‘cash at bank and in hand’ is cash on Amounts in US$ '000 Liabilities as per statement of financial position Trade payables Payables to related parties To be paid to co-venturers Borrowings at amortised cost 2014 2013 64,457 16,591 1,335 61,130 8,456 1,201 369,593 317,087 451,976 387,874 Credit quality of financial assets The credit quality of financial assets that are neither past due nor impaired can be assessed by reference to external credit ratings (if available) or to historical information about counterparty default rates: Amounts in US$ '000 2014 2013 Financial liabilities - contractual undiscounted cash flows The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows. Between Between Less than 1 and 2 2 and 5 Amounts in US$ '000 1 year years years Over 5 years At 31 December 2014 Borrowings Trade payables Payables to related parties Trade receivables Counterparties with an external credit rating (Moody’s) Ba2 Baa2 Baa3 At 31 December 2013 Borrowings Trade payables - Payables to related parties 2,048 17,321 11,793 - 11,292 Counterparties without an external credit rating Group1 (*) Total trade receivables 13,832 36,917 23,259 42,628 (*) 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. 41,124 64,457 1,325 40,342 109,152 322,500 - - 1,325 17,226 - - 106,906 41,667 126,378 322,500 39,585 61,130 8,456 22,600 67,500 345,000 - - - - - - 109,171 22,600 67,500 345,000 GeoPark 20F 213 GeoPark 20F 213 Note 25 Share capital Issued share capital Common stock (amounts in US$ '000) The share capital is distributed as follows: 2014 58 On 17 September 2013, 295,599 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”), generating a share premium of US$ 3,441,689. On 22 October 2012, 976,211 common shares were allotted to 2013 the trustee of the EBT, generating a share premium of US$ 4,191,000. 44 On 29 October 2013, the Company put into place an irrevocable, non- discretionary share purchase program for the purchase of its common shares Common shares, of nominal US$ 0.001 Total common shares in issue 57,790,533 57,790,533 43,861,614 for the account of the EBT. This Purchase Program expired on 31 December 43,861,614 2013. The common shares purchased under the program will be used to Authorised share capital US$ per share Number of common shares (US$ 0.001 each) Amount in US$ satisfy future awards under the incentive schemes. During 2013, the Company purchased 50,000 common shares for a total amount of US$ 440,000. 0.001 0.001 5,171,949,000 5,171,949,000 statement upon which 13,999,700 shares were issued at a price of US$ 7 5,171,949 5,171,949 per share, including over-allotment option. Gross proceeds from the offering On 7 February 2014, the SEC declared effective the Company’s registration totalled US$ 98 million (see Note 1). Details regarding the share capital of the Company are set out below: On 19 December 2014, the Company approved a program to repurchase up Common shares As of 31 December 2014, the outstanding common shares confer the to US$ 10 million of common shares, par value US$ 0.001 per share of the Company (the “Repurchase Program”). The Repurchase Program began on following rights on the holder: • the right to one vote per share; 19 December 2014 and will expire at the close of business on March 27, 2015, but may be terminated prior to such date. The Shares repurchased will • ranking pari passu, the right to any dividend declared and payable on be used to offset, in part, any expected dilution effects resulting from the common shares; GeoPark Company’s employee incentive schemes, including grants under the Company’s Stock Award Plan and the Limited Non-Executive Director Plan. Shares issued Shares closing US$ During 2014, the Company purchased 73,082 common shares for a total (´000) amount of US$ 388,000. This transaction had no impact on the Company’s common shares history Date (millions) (millions) closing results. Shares outstanding at the end of 2011 Issue of shares to 42.5 43 During 2014, the Company issued 2,301 (10,430 in 2013 and 15,100 in 2012) shares to Non-Executive Directors in accordance with contracts as Non-Executive Directors Stock awards 2012 Oct 2012 0.02 1.01 42.5 43.5 43 43 compensation, generating a share premium of US$ 22,413 (US$ 100,988 in 2013 and US$ 142,492 in 2012). The amount of shares issued is determined 43.5 43 for each relevant period. considering the contractual compensation and the fair value of the shares 0.01 0.46 (0.1) 14.0 0.0 (0.1) 43.5 44.0 43.9 43.9 57.9 57.9 57.8 57.8 43 44 44 44 58 58 58 58 Under the stock awards programmes and other share based payments, during 2013, 60,000 (30,000 in 2012) new common shares were issued, pursuant to a consulting agreement for services rendered to GeoPark Limited generating a share premium of US$ 506,630 (US$ 253,315 in 2012). The accounting treatment of the shares is in line with the Group’s policy on share-based payment. Shares outstanding at the end of 2012 Issue of shares to Non-Executive Directors 2013 Stock awards Buyback program Shares outstanding at the end of 2013 IPO Stock awards Buyback program Shares outstanding at the end of 2014 Sept 2013 Oct 2013 Feb 2014 Feb 2014 Dec 2014 214 GeoPark 20F 214 GeoPark 20F Other Reserve During 2012, LGI acquired a 20% interest in the Colombian business by Under the terms of the Notes, the Issuer is required to comply with certain financial covenants for the incurrence of additional debt and other specific making a capital contribution for an amount of US$ 14,920,000. The corporate actions (dividends, mergers, etc.) consisting on: i) Leverage Ratio, differences between total consideration and the net equity of the Companies defined as Gross Debt to Adjusted EBITDA, lower than 2.75x for the year as per the book value were recorded as Other Reserve in the Consolidated 2014 and lower than 2.5x from 2015 onwards; and ii) Interest Coverage Ratio, Statement of Changes in Equity (see Note 34.b). defined as Adjusted EBITDA divided by Interest Expenses, above 3.5x. Note 26 Borrowings As of the date of these consolidated financial statements, the Company has complied with these covenants. (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% Amounts in US$ '000 2014 2013 working interest in the Manatí field in Brazil (see Note 34.c). The interest rate 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) Overdrafts(e) applicable to this loan is LIBOR plus 3.9% per annum. The interest will be 300,963 299,912 paid semi-annually; principal will be cancelled semi-annually with a year 68,540 - grace period. The debt issuance cost for this transaction amounted to 90 - - 2,143 US$ 3,295,000. The facility agreement includes customary events of default, 15,002 and requires the Brazilian subsidiary to comply with customary covenants, 30 including the maintenance of a ratio of net debt to EBITDA of up to 3.5x Classified as follows: Non current Current 369,593 317,087 for the first two years and up to 3.0x thereafter. The credit facility also limits 342,440 27,153 the borrower’s ability to pay dividends if the ratio of net debt to EBITDA 290,457 is greater than 2.5x. As of the date of these consolidated financial statements, 26,630 the Company has complied with these covenants. The fair value of these financial instruments at 31 December 2014 amounts (c) Facility to establish the operational base in the Fell Block. This facility to US$ 360,181,000 (US$ 312,208,000 in 2013). The fair values are based was acquired through a mortgage loan granted by the Banco de Crédito e on cash flows discounted using a rate based on the borrowing rate of 7.40% Inversiones (BCI), a Chilean private bank. The loan was granted in Chilean (2013: 7.81%) and are within level 2 of the fair value hierarchy. pesos and is repayable over a period of 8 years. The interest rate applicable to this loan is 6.6%. The outstanding amount at 31 December 2014 is (a) During February 2013, the Company successfully placed US$ 300 million US$ 90,000 (US$ 212,000 in 2013). notes which were offered under Rule 144A and Regulation S exemptions of the United States Securities laws. The Notes, issued by the Company's wholly-owned subsidiary GeoPark Latin In addition, during 2011, GeoPark TdF obtained financing from BCI to start the operations in the newly acquired blocks. The outstanding amount at 31 December 2013 was US$ 1,931,000. This financing was structured as letter America Limited Agencia en Chile (“the Issuer”), were priced at 99.332% and of credit and was fully repaid in February 2014. carry a coupon of 7.50% per annum to yield 7.625% per annum. Final maturity of the notes will be 11 February 2020. The Notes are guaranteed by GeoPark (d) Short term financing obtained in December 2013 and fully repaid in Limited and GeoPark Latin America Coöperatie U.A. and are secured with January 2014. The interest rate applicable to this loan was 0.71% per annum. a pledge of all of the equity interests of the Issuer in GeoPark Chile S.A. and GeoPark Colombia Coöperatie U.A. and a pledge of certain intercompany (e) The Group has been granted with credit lines for over US$ 69,000,000. loans. Notes were rated single B by both Standard & Poor's and Fitch Ratings. The exercise of these credit lines could be limited by debt covenants The debt issuance cost for this transaction amounted to US$ 7,637,000. associated to other borrowings. GeoPark 20F 215 GeoPark 20F 215 Note 27 Provisions and other long-term liabilities Asset retirement Deferred Amounts in US$ '000 obligation At 1 January 2012 Addition to provision/ Contributions received Acquisition of subsidiaries 5,450 3,440 6,061 income 3,962 5,550 - Amortisation Unwinding of discount At 31 December 2012 Addition to provision Recovery of - (2,143) 1,262 16,213 7,183 - 7,369 - abandonments costs (753) - - (1,165) Amortisation Unwinding of discount At 31 December 2013 Addition to provision Recovery of abandonments costs Acquisition of subsidiaries Exchange difference Amortisation 1,523 24,166 1,603 (1,317) 6,862 - - Unwinding of discount At 31 December 2014 1,972 33,286 - 6,204 - - - - (468) - 5,736 Note 28 Trade and other payables Amounts in US$ '000 V.A.T Total 9,412 9,090 8,370 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 (2,143) To be paid to co-ventures 1,262 25,991 7,480 (753) Classified as follows: Non current Current 2014 3,449 64,457 16,591 7,226 2,398 10,031 1,335 2013 8,074 61,130 8,456 8,551 3,375 9,190 1,201 105,487 99,977 16,583 88,904 8,344 91,633 (1,165) (1) As of 31 December 2014, the outstanding amount corresponds to a loan 1,523 granted by LGI to GeoPark Chile S.A. for financing Chilean operations in TdF’s Other - 100 2,309 - - 2,409 297 - - - 2,706 5,934 33,076 7,537 blocks. The maturity of this loan is July 2017 and the applicable interest rate is 8% per annum. As of 31 December 2013, the outstanding amount relates to - - (752) - - a loan granted by LGI as part of its funding commitment in connection with (1,317) Colombian companies acquisition (see Note 34.b). This loan was cancelled 6,862 during 2014. (752) (468) The average credit period (expressed as creditor days) during the year ended 1,972 31 December 2014 was 50 days (2013: 58 days) 7,888 46,910 The fair value of these short-term financial instruments is not individually The provision for asset retirement obligation relates to the estimation of determined as the carrying amount is a reasonable approximation of future disbursements related to the abandonment and decommissioning of fair value. oil and gas wells (see Note 4). Deferred income relates to contributions received to improve the project economics of the gas wells. The amortisation is in line with the related asset. Other mainly relates to fiscal controversies associated to income taxes in one of the Colombian subsidiaries. These controversies relate to fiscal periods prior to the acquisition of these subsidiaries by the Company. In connection to this, the Company has recorded an account receivable with the previous owners for the same amount, which is recognized under Other financial assets in the Balance sheet. 216 GeoPark 20F 216 GeoPark 20F Note 29 Share-based payment IPO Award Programme and Executive Stock Option plan The Group has established different stock awards programmes and other Main characteristics of these news plans are: • Exercise price: US$ 0.001. • Grant date: July 2013. • Grant price: £ 5.8. • Vesting date: 31 December 2015. share-based payment plans to incentivise the Directors, senior management • Conditions to be able to exercise: and employees, enabling them to benefit from the increased market - Continue to be an employee. capitalization of the Company. - Obtain the Company minimum Production, Adjusted EBITDA and Reserves Stock Award Programmes and Other Share Based Payments During 2008, GeoPark Shareholders voted to authorize the Board to use up to 12% of the issued share capital of the Company at the relevant time for target for the year of vesting. - The stock market price at the date of vesting should be higher than the share price at the price of grant. • Amount of shares for equity-settled plan: 500,000. the purposes of the Performance-based Employee Long-Term Incentive Plan. • Estimated equivalent amount of shares for cash-settled plan: 500,000. Main characteristics of the Stock Awards Programmes are: • All employees are eligible. According to current market conditions, the Company estimated that for the cash awards plan, the share price at the vesting date would not reach • Exercise price is equal to the nominal value of shares. the threshold for granting. Therefore, no liability has been recognized • Vesting period is four years. as of 31 December 2014. • Specific Award amounts are reviewed and approved by the Executive Directors and the Remuneration Committee of the Board of Directors. Also during 2013, the Company approved a plan named Value creation plan (“VCP”) oriented to Top Management. The VCP establishes awards payables On 23 November 2012, the Remuneration Committee and the board of in a variable number of shares with some limitation, subject to certain market directors approved granting 720,000 options over ordinary shares of conditions, among others, reach certain stock market price for the Company US$ 0.001 each to the Executive Directors. Options granted vest on the third share at vesting date. VCP has been classified as an equity-settled plan. anniversary of the date on which they are granted and have an exercise price of US$ 0.001. Additionally, during 2013 the Company approved two new share-based compensation programmes: i.) a stock awards plan oriented to Managers (non-Top Management) and key employees which qualifies as an equity- settled plan and ii.) a cash awards plan, oriented to all non-management employees which qualifies as a cash-settled plan. GeoPark 20F 217 GeoPark 20F 217 Details of these costs and the characteristics of the different stock awards programmes and other share based payments are described in the following table and explanations: Year of issuance 2013 2012 2011 2010 2008 Subtotal Stock options to Executive Directors Shares granted to Non-Executive Directors VCP Awards at the beginning 500,000 443,000 494,000 835,600 - 720,000 Awards granted in the year - - - - - - - - 26,259 - Awards forfeited 22,000 15,000 16,000 18,000 - - - - Awards Awards at exercised year end 478,000 428,000 478,000 817,600 - - - - - - - Charged to net profit 2014 1,291 1,102 848 2,623 - 5,864 2013 619 1,296 893 2,779 - 5,587 720,000 2,474 2,365 2,301 - 23,958 - 223 617 9,178 101 309 8,362 2012 - 55 926 2,929 1,087 4,997 257 142 - 5,396 2,992,600 26,259 71,000 2,301 2,945,558 The awards that are forfeited correspond to employees that had left the Group before vesting date. Other share-based payment As it is mentioned in Note 25, the Company granted 2,301 (10,430 in 2013 and 15,100 in 2012) shares for services rendered by the Non-Executive Directors of the Company. Fees paid in shares were directly expensed in the Administrative costs line in the amount of US$ 22,413 (US$ 100,988 in 2013 and US$ 142,492 in 2012). On 19 December 2014, the Company has approved a new share-based compensation programme for 500,000 shares oriented to new employees. This new programme, which was granted on 31 December 2014, has a vesting period of three years. 218 GeoPark 20F 218 GeoPark 20F Note 30 Interests in Joint operations The Group has interests in nine joint operations, which are involved 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 2014 GeoPark Magallanes Ltda. Tranquilo Block Otway Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Llanos 17 Block Interest 50% 100% 50% 50% 60% 36.84% Yamu/Carupana Block 90% - 79.5% 45% 10% Llanos 34 Block Llanos 32 Block GeoPark Brazil Exploração y Produção de Petróleo e Gas Ltda. Manatí Field PP&E E&E Other assets Total assets Current liabilities Total Net assets/ Net Operating liabilities (liabilities) revenue profit (loss) 109 139 35,110 34,309 12,208 6,037 16,590 76,726 8,909 - - - - - - 2,211 1,514 27 109 139 35,110 34,309 12,208 6,037 18,801 78,240 8,936 (125) (146) (1,653) (7,086) (241) (122) (2,727) (3,380) (122) (125) (146) (1,653) (7,086) (241) (122) (2,727) (3,380) (122) (16) (7) 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 (220) (12) (6,278) (6,151) (283) (160) (2,916) 96,889 4,041 10% 46,382 43,891 90,273 (11,587) (11,587) 78,686 35,621 18,935 GeoPark 20F 219 GeoPark 20F 219 Subsidiary / Joint operation 2013 GeoPark Magallanes Ltda. Tranquilo Block Otway Block GeoPark TdF S.A. Flamenco Block Campanario Block Isla Norte Block Colombia SAS Llanos 17 Block Interest 29% 100% 50% 50% 60% 36.84% Yamu/Carupana Block 75% - 54.50% Llanos 34 Block Llanos 32 Block 2012 GeoPark Magallanes Ltda. Tranquilo Block Otway Block Colombia SAS Llanos 17 Block 45% 10% 29% 25% 36.84% Yamu/Carupana Block 75% - 54.50% Llanos 34 Block Llanos 32 Block 45% 10% PP&E E&E Other assets Total assets Current liabilities Total Net assets/ Net Operating liabilities (liabilities) revenue profit (loss) 15,255 6,009 42,048 17,172 4,497 6,448 15,476 51,963 4,993 13,328 6,516 3,872 12,626 25,178 4,384 210 175 - - - 29 482 1,129 - 1,467 1,326 144 26 72 1,484 15,465 6,184 42,048 17,172 4,497 6,477 15,958 53,092 4,993 14,795 7,842 4,016 12,652 25,250 5,868 (391) (48) (2,537) (405) (303) - - - - (391) (48) (2,537) (405) (303) - - - - (3,252) (2,412) (3,252) (2,412) (224) (224) - - - - (1,509) (1,509) 15,074 6,136 39,511 16,767 4,194 6,477 15,958 53,092 4,993 11,543 5,430 3,792 12,652 25,250 4,359 - - 243 - - 1,407 17,727 78,390 5,507 - - 144 23,283 10,362 2,900 (275) (100) (239) - - (544) 2,127 39,192 1,035 (544) (386) 144 4,034 3,767 1,207 Capital commitments are disclosed in Note 31 (b). Note 31 Commitments 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: (a) Royalty commitments 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 and a rate which ranges between 6%-8%. The When the API is lower than 15°, the payment is reduced to the 75% of the Colombian National Hydrocarbons Agency (“ANH”) also has an additional total calculation. economic right equivalent to 1% of production, net of royalties. 220 GeoPark 20F In accordance with Llanos 34 Block operation contract, when the (b) Capital commitments accumulated production of each field, including the royalties’ volume, exceeds 5 million of barrels and the WTI exceeds the base price settled in table a, the Company should deliver to ANH a share of the production net Chile As of 31 December 2014 the only remaining commitments in Chile are of royalties in accordance with the following formula: Q = ((P - Po)/P) x S; related to Tierra del Fuego blocks. The future investment commitments where Q = Economic right to be delivered to ANH, P = WTI, Po = Base price assumed by GeoPark outstanding are: (see table A) and S = Share (see table B). Table A °API >29° >22°<29° >15°<22° >10°<15° Table B • Isla Norte Block: 2 exploratory wells before November 2015 (US$ 6,480,000). • Campanario Block: 3 exploratory wells before January 2016 (US$ 11,880,000). Po (US$/barrel) WTI (P) 30.22 31.39 Po < P < 2Po 2Po < P < 3Po 32.56 46.50 3Po < P < 4Po 4Po < P < 5Po 5Po < P S 30% 35% 40% 45% 50% The investments made in the first exploratory period will be assumed 100% by GeoPark. As of 31 December 2014, the Company has established a guarantee for its commitments that amounts to US$ 17,500,000. Colombia For the Llanos 17 Block, the activities were performed but there is still a Additionally, under the terms of the Winchester Stock Purchase Agreement, remaining commitment that amounts to US$ 4,299,000 (US$ 1,584,000 we are obligated to make certain payments to the previous owners of at GeoPark’s working interest (36.84%)) which is expected to be completed Winchester based on the production and sale of hydrocarbons discovered by with an additional well. exploration wells drilled after October 25, 2011. These payments involve both an earnings based measure and an overriding royalty equal to an The Llanos 62 Block (100% working interest) has committed to drill two estimated 4% carried interest on the part of the vendor. As at the balance exploratory wells before July 2015. The remaining commitment amounts to sheet date and based on preliminary internal estimates of additions US$ 6,000,000. of 2P reserves since acquisition, the Company’s best estimate of the total commitment over the remaining life of the concession is a range of The VIM 3 Block minimum investment program consists of 200 sq km of 2D US$ 50 million - US$ 60 million. During 2014, the Company has accrued and seismic and drilling one exploratory well, with a total estimated investment of paid US$ 24.6 million (US$ 11.5 million in 2013 and US$ 1.3 million in 2012) US$ 22,200,000 during the initial three year exploratory period ending in and US$ 21.0 million (US$ 7.8 million in 2013), respectively. September 2018. In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency In accordance with the farm-in agreement, and subject to the approval of (ANP) is responsible for determining monthly minimum prices for petroleum Agencia Nacional de Hidrocarburos (ANH) in Colombia, GeoPark will operate produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between and receive a 50% working interest (WI) in the CPO-4 Block in exchange for its commitment to drill and fund its 50% WI (with no carry) of one exploration 5% and 10% applied to reference prices for oil or natural gas, as established in well before August 2015. The financial commitment for GeoPark is the relevant bidding guidelines (edital de licitação) and concession approximately US$ 6,000,000. agreement. In determining the percentage of royalties applicable to a particular concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. In the Brazil On 14 May 2013, the ANP awarded GeoPark seven new concessions in Manatí Block, royalties are calculated at 7.5% of gas production. Brazil in an international bidding round, Round 11. For these seven In Argentina, crude oil production accrues royalties payable to the Provinces (including bonuses and work program commitment) during the first three of Santa Cruz and Mendoza equivalent to 12% on estimated value at well years of the exploratory period for the concessions. GeoPark has already head of those products. This value is equivalent to final sales price less invested US$ 5,400,000 in seismic and US$ 4,400,000 in bonuses paid to ANP. concessions, GeoPark committed to invest a minimum of US$ 15,300,000 transport, storage and treatment costs. GeoPark 20F 221 On 28 November 2013, the ANP awarded GeoPark two new concessions Note 32 in a new international bidding round, Round 12. For these two concessions, Related parties GeoPark have committed to invest a minimum of US$ 4,000,000 (including bonus and work program commitments) during the first exploratory period. Controlling interest For PN-T-597 Block the commitment amounts to US$ 3,300,000 and for the SEAL-T-268 Block is US$ 700,000. See Note 34 for further details. The main shareholders of GeoPark Limited, a company registered in Bermuda, as of 31 December 2014, 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 blocks cover an area of approximately 1.7 million acres and are located in the Neuquen Basin, Argentina's largest producing hydrocarbon basin. 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. Shareholder Gerald E. O’Shaughnessy(1) James F. Park(2) Steven J. Quamme(3) IFC Equity Investments(4) Moneda A.F.I.(5) Juan Cristóbal Pavez(6) BTG Pactual Charles Schwab & Co. Other shareholders Common shares 7,533,907 7,441,269 9,699,161 3,456,594 2,741,650 2,887,130 4,518,886 4,352,780 15,159,156 57,790,533 Percentage of outstanding common shares 13.04% 12.88% 16.78% 5.98% 4.74% 5.00% 7.82% 7.53% 26.23% 100.00% (c) Operating lease commitments - Group company as lessee The Group leases various plant and machinery under non-cancellable Resources Group Inc., all of which are controlled by Mr. O’Shaughnessy. (2) Held by Energy Holdings, LLC, which is controlled by James F. Park, (1) Held directly and indirectly through GP Investments LLP, and The Globe operating lease agreements. a member of our Board of Directors. The number of common shares held by Mr. Park does not reflect the 588,664 common shares held as The Group also leases offices under non-cancellable operating lease of 31 December 2014 in the employee benefit trust described under agreements. The lease terms are between 2 and 3 years, and the majority of ‘‘Management-Compensation-Employee Benefit Trust’’. lease agreements are renewable at the end of the lease period at market rate. (3) Held through certain private investment funds managed and controlled by Cartica Management, LLC. The common shares reflected as being During 2014 a total amount of US$ 19,409,000 (US$ 19,110,000 in 2013 and US$ 4,531,000 in 2012) was charged to the income statement and held by Mr. Quamme include 8,189 common shares held by him personally. Mr. Steven Quamme, one of our principal shareholders and a member of our US$ 51,341,000 of operating leases were capitalised as Property, plant and board of directors, is the Senior Managing Director of Cartica Management, equipment (US$ 37,263,000 in 2013 and US$ 32,706,000 in 2012). LLC, and therefore may be deemed to have voting and investment power The future aggregate minimum lease payments under non-cancellable (4) IFC Equity Investments voting decisions are made through a portfolio operating leases are as follows: management process which involves consultation from investment officers, over the common shares of GeoPark held by Cartica Management, LLC. credit officers, managers and legal staff. Amounts in US$ '000 2014 2013 2012 (5) Held through various funds managed by Moneda A.F.I. (Administradora 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 37,926 33,949 16,109 505 68,817 56,556 31,145 505 de Fondos de Inversión), an asset manager. 26,464 (6) Held through Socoservin Overseas Ltd, which is controlled by Juan 3,709 Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 9,326 common shares held by him personally. 443 895 Total minimum lease payments 88,489 157,023 31,511 222 GeoPark 20F 222 GeoPark 20F Balances outstanding and transactions with related parties Account (Amounts in ´000) 2014 To be recovered from co-ventures Payables account To be paid to co-venturers Financial expenses Exploration costs Administrative costs Administrative costs 2013 To be recovered from co-ventures Payables account To be paid to co-venturers Financial expenses Exploration costs Administrative costs 2012 To be recovered from co-ventures Prepayment and other receivables To be paid to co-venturers Exploration costs Administrative costs Transaction in the year Balances at year end Related party Relationship - - - 592 16 114 568 - - - 112 24 176 - - - 31 219 5,931 (16,591) (1,335) - - - - Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations LGI Partner Carlos Gulisano Carlos Gulisano Pedro Aylwin Non-Executive Director(*) Non-Executive Director(*) Executive Director(**) 15,508 (8,456) (1,201) Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations - - - 8,773 31,138 (2,007) - - LGI Carlos Gulisano Carlos Gulisano Partner Non-Executive Director(*) Non-Executive Director(*) Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations Carlos Gulisano Carlos Gulisano Non-Executive Director(*) Non-Executive Director(*) (*) Corresponding to consultancy services. (**) Corresponding to: wages and salaries for US$ 374,000 and bonus for US$ 194,000. 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. GeoPark 20F 223 GeoPark 20F 223 Note 33 Fees paid to Auditors Amounts in US$ ´000 Fees payable to the Group’s auditors for the audit of the which involve both, an earnings based measure and an overriding revenue royalty, equate to an estimated 4% carried interest on the part of the vendor. 2014 2013 2012 The following table summarises the combined consideration paid for Winchester Luna and Hupecol, the fair value of assets acquired and liabilities assumed for these transactions: consolidated financial statements 381 668(*) 346 Amounts in US$ ´000 Hupecol Luna Total Winchester Fees payable to the Group’s auditors for the review of interim financial statements Fees payable for the audit of the Group’s subsidiaries pursuant to legislation Fees payable to the Group’s auditors for the review of 20-F Non-audit services Fees paid to auditors 128 150 52 Cash (including working 36 70 826 273 - 337 capital adjustments) Total consideration Cash and cash equivalents 298 Property, plant and equipment - (including mineral interest) 713 Trade receivables 1,441 1,428 1,409 Prepayments and other receivables (*) Include fees related to the 2013 IPO process. Deferred income tax assets Inventories Non-audit services relates to tax services for US$ 281,000 (US$ 292,000 in Borrowings - Trade payables and other debt (20,487) 2013 and US$ 121,000 in 2012) and due diligence, consultancy fees and other Provision for other services for US$ 545,000 (US$ 45,000 in 2013 and US$ 592,000 in 2012). long-term liabilities 79,630 79,630 976 73,791 4,402 5,640 10,344 10,596 32,243 32,243 5,594 111,873 111,873 6,570 37,182 110,973 4,098 2,983 5,262 1,612 (11,981) (1,368) 8,500 8,623 15,606 12,208 (32,468) (1,368) (5,632) 79,630 (2,738) (8,370) 40,644 120,274 - 8,401 8,401 Total identifiable net assets Bargain purchase gain on acquisition of subsidiaries(1) Note 34 Business transactions a. Colombia Acquisitions in Colombia On 14 February 2012, GeoPark acquired two privately-held exploration and production companies operating in Colombia, Winchester Oil and Gas S.A. and La Luna Oil Company Limited S.A. (“Winchester Luna”). (1) The bargain purchase gain is related to the fact that the Company paid a full market price for the proved reserves but received a discount on the probable and possible reserves and resource base acquired due to the vendor’s limited ability to fund the future development of these assets. The purchase price allocation above mentioned is final. For accounting purposes, these acquisitions were computed as if they Acquisition-related costs have been charged to administrative expenses in had occurred on 1 February 2012. the consolidated income statement for the year ended 31 December 2012. On 27 March 2012, a second acquisition occurred with the purchase of New exploratory license: VIM-3 Block Hupecol Cuerva LLC (“Hupecol”), a privately-held company with two GeoPark expanded in Colombia through the award of a new exploratory exploration and production blocks in Colombia. For accounting purposes, license during the 2014 Colombia Bidding Round, carried out by the Agencia this acquisition was computed as if it had occurred on 1 April 2012. Nacional de Hidrocarburos (“ANH”) on 23 July 2014 in Cartagena, Colombia. Under the terms of the sale and purchase agreement entered into in 2012 in GeoPark was awarded the VIM-3 Block in the Lower Magdalena Basin, respect of the acquisition of Winchester Luna, the Company has to make covering an area of approximately 225,000 acres. The block has an attractive certain payments to the former owners arising from the production and sale oil and gas exploration potential in a large area within a proven hydrocarbon of hydrocarbons discovered by exploration wells drilled after 25 October 2011 system, surrounded by existing oil and gas fields and with sparse exploration on the working interests of the companies at that date. These payments activity carried out to date. 224 GeoPark 20F 224 GeoPark 20F 224 GeoPark 20F GeoPark’s winning bid consisted of committing to a minimum investment During 2012, LGI also joined GeoPark’s operations in Colombia through the program of 200 sq km of 2D seismic and drilling one exploration well, acquisition of 20% interest in Colombian Business. In addition, LGI committed with a total estimated investment of US$ 22.2 million during the initial three to fund Colombian operations through the granting of loans. year exploratory period and a Royalty X Factor of 3% (see Note 31). GeoPark will operate and have a 100% working interest in the block. In addition, in March 2013 GeoPark and LGI announced their agreement to extend their strategic alliance to build a portfolio of upstream oil and gas New exploratory license: CPO-4 Block assets throughout Latin America through 2015. On 4 November 2014, the Company expanded its operations in Colombia with the addition of the CPO-4 Block to its portfolio through a partnership c. Brazil agreement with SK Innovation (subsidiary of SK Group, the Korean integrated energy and petrochemical company). Acquisition in Brazil GeoPark entered into Brazil with the acquisition of a 10% working interest The CPO-4 Block is an attractive high potential block on trend with GeoPark’s in the offshore Manatí gas field (“Manatí Field”), the largest natural gas successful Llanos 34 Block in the Llanos Basin (approximately 60 km away). producing field in Brazil. On 14 May, 2013, GeoPark executed a stock purchase The CPO-4 Block covers an area of approximately 345,600 acres (1,398 sq km) agreement (“SPA”) with Panoro Energy do Brazil Ltda., the subsidiary of with 3D seismic coverage of approximately 880 sq km and sparse drilling Panoro Energy ASA, (“Panoro”), a Norwegian listed company with assets in activity (with only 4 wells drilled to date). SK and GeoPark have jointly Brazil and Africa, to acquire all of the issued and outstanding shares of its identified new prospects in CPO-4 similar to prospects and leads in GeoPark’s wholly-owned Brazilian subsidiary, Rio das Contas Produtora de Petróleo Ltda Llanos 34 Block where GeoPark has successfully discovered oil. (“Rio das Contas”), the direct owner of 10% of the BCAM-40 Block (the “Block”), which includes the shallow-depth offshore Manatí Field in the In accordance with the farm-in agreement, and subject to the approval of Camamu-Almada Basin. Agencia Nacional de Hidrocarburos (ANH) in Colombia, GeoPark will operate and receive a 50% working interest (WI) in the CPO-4 Block in exchange for GeoPark has paid a cash consideration of US$ 140 million at 31 March 2014 its commitment to drill and fund its 50% WI (with no carry) of one exploration or the closing date, which was adjusted for working capital with an effective well. GeoPark’s total financial commitment is approximately $6.0 million date of 30 April 2013. The agreement also provides for possible future (see Note 31). There is an option to move to an additional exploration phase contingent payments by GeoPark over the next five years, depending on following the drilling of a successful well. the economic performance and cash generation of the block. The Company Swap operation On 29 July 2014, GeoPark’s Colombian subsidiary agreed to exchange its 10% has estimated that there are no any future contingent payments at the acquisition date and as of the date of these financial statements either. non-operating economic interest in Arrendajo Block for additional interests The Manatí Field is a strategically important, profitable upstream asset in held by the counterpart in the Yamú Block (GeoPark operated) that includes a 15% economic interest in all of the Yamú fields except for the Carupana Brazil and currently provides approximately 50% of the gas supplied to the northeastern region of Brazil and more than 75% of the gas supplied to field, where the counterparty had a 25% economic interest. According to Salvador, the largest city and capital of the northeastern state of Bahia. the terms of the exchange, GeoPark received US$ 3.2 million in cash from the The field is largely developed with existing producing wells and an extensive exchange, adjusted by working capital. Following this transaction, GeoPark pipeline, treatment and delivery infrastructure and is not expected to will continue to be the operator and have a 79.5% interest in the Carupana require significant future capital expenditures to meet current production Field and 90% in Yamú and Potrillo Fields, all fields located in the Yamú Block. estimates. Additional reserve development may be possible. This transaction had no impact on the results of the Company. b. LGI partnership On 12 March 2010, LGI and the Company agreed to form a new strategic the Brazilian national company, largest oil and gas operator in Brazil and internationally-respected offshore operator. Other partners in the partnership to jointly acquire and develop upstream oil and gas projects in Block include Queiroz Galvao Exploração e Produção (45% working interest) Latin America. and Brasoil Manatí Exploração Petrolífera S.A. (10% working interest). The Manatí Field is operated by Petrobras (35% working interest), During 2011, GeoPark and LGI entered into several agreements through In accordance with the acquisition method of accounting, the acquisition cost which LGI acquires 20% interest in the Chilean Business of the Group. was allocated to the underlying assets acquired and liabilities assumed based primarily upon their estimated fair values at the date of acquisition. GeoPark 20F 225 GeoPark 20F 225 GeoPark 20F 225 An income approach (being the net present value of expected future cash flows) Round 12 was adopted to determine the fair values of the mineral interest. Estimates On 28 November 2013, the ANP awarded GeoPark with two new concessions of expected future cash flows reflect estimates of projected future revenues, in a new international bidding round, Round 12. production costs and capital expenditures based on our business model. In Brazil, GeoPark Brazil is currently a party to a legal proceeding related to The following table summarises the consideration paid, the fair value of assets the concession agreement of Block PN-T-597 that the ANP initially awarded acquired and liabilities assumed for the abovementioned transaction: to GeoPark Brazil in the 12th oil and gas bidding round. As a result of a Amounts in US$ '000 Total by a Brazilian Federal Court against the ANP, the Federal Government and Cash (including working capital adjustments) 140,100 GeoPark Brazil on 13 December 2013. Due to the injunction GeoPark Total consideration Cash and cash equivalents 140,100 25,133 Brazil could not proceed to execute the concession agreement, and cannot do so until the injunction is lifted. According to the terms of the Court’s Property, plant and equipment (including mineral interest) 112,847 injunction, the ANP will first need to take certain actions, such as conducting class action filed by the Federal Prosecutor’s Office, an injunction was issued 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 studies that prove that drilling unconventional resources will not contaminate the dams and aquifers in the region. On 21 February 2014, GeoPark Brazil 950 requested that the board of the ANP suspend the execution of the concession (3,132) (4,538) (6,862) agreement (which entails delivery of the financial guarantee and performance guarantee and payment of the signing bonus) for six months with a possible extension of an additional six months, or until a firm court 140,100 decision is reached that does not prevent GeoPark Brazil from entering into the concession agreement. On 16 April 2014, the ANP’s Board enacted a The purchase price allocation above mentioned is final. Acquisition-related resolution stating that all proceedings related to the award of the concession costs have been charged to administrative expenses in the consolidated of Block PN-T-597 to GeoPark Brazil were suspended. income statement for the year ended 31 December 2012. The revenue included in the consolidated statement of comprehensive d. Peru income since acquisition date contributed by the acquired company was US$ 35,621,000. The acquired company also contributed profit of US$ 18,952,000 Entry in Peru The Company has executed a Joint Investment Agreement and Joint over the same period. Operating Agreement with Petróleos del Perú S.A. (“Petroperú”) to acquire an interest in and operate the Morona Block located in northern Peru. GeoPark Had Rio das Contas been consolidated from 1 January 2014 the consolidated will assume a 75% working interest (“WI”) of the Morona Block, with statement of income would show pro-forma revenue of US$ 440,298,000 and profit of US$ 23,139,000. Petroperú retaining a 25% WI. The transaction has been approved by the Board of Directors of both Petroperú and GeoPark. Round 11 On 14 May 2013, the Company has been awarded seven new licenses in the The transaction is subject to customary conditions, certain license modifications and a presidential decree. The transaction is expected to close Brazilian Round 11 of which two are in the Reconcavo Basin in the State of by the second half of 2015. Bahia and five are in the Potiguar Basin in the State of Rio Grande do Norte. The licensing round was organized by the ANP and all proceedings and bids on the western side of the Marañón Basin, one of the most prolific have been made public. On 17 September 2013, the winning bids were hydrocarbon basins in Peru. The Morona Block, also known as Lote 64, covers an area of 1.9 million acres approved by the ANP. For its winning bids on the seven blocks, GeoPark has committed to invest a delineated by two wells (with short term tests of approximately 2,400 and minimum of US$ 15.3 million (including bonus and work program 5,200 bopd of 35-36° API oil each) and by 3D seismic. In addition to the commitment) during the first 3 years of the exploratory period (see Note 31). Situche Central field, the Morona Block has a large exploration potential The new blocks cover an area of approximately 54,850 acres. with several high impact prospects and plays - with exploration resources The Morona Block contains the Situche Central oil field, which has been currently estimated to range from 200 to 600 mmbo. 226 GeoPark 20F 226 GeoPark 20F 226 GeoPark 20F The Morona Block includes geophysical surveys of 2,783 km (2D seismic) 500,000 SCM/d (subject to certain exceptions based on methanol prices). and 465 sq km (3D seismic), and an operating field camp and logistics The amendment also provides for temporary DOP and TOP thresholds of infrastructure. The expected work program and development plan for the 100% and 50%, respectively. As of 31 December 2013, the Company fulfilled Situche Central oil field is to be completed in three stages. the delivery volume commitment. The goal of the initial stage will be to put the field into production through On 1 April 2014, the Company and Methanex executed a fifth amendment a long term test to help determine the most effective overall development to the Gas Supply Agreement, valid until 30 April 2015, which extended the plan and to begin to generate cash flow. This initial stage requires fourth amendment conditions until 18 May 2014, and defined new conditions an investment of approximately US$ 140 million to US$ 160 million and is for the winter 2014 period (May 2014 to September 2014) and the post winter expected to be completed within 18 to 24 months after closing. GeoPark period (October 2014 to April 2015). During the winter 2014 period the has committed to carry Petroperú during this initial phase. The subsequent price was fixed on US$ 4.0 per mmbtu plus 50% of any price difference that work program stages, which will be initiated once production has been Methanex obtained if gas were delivered to third parties. For the post winter established, are focused on carrying out the full development of the Situche period the Company committed deliveries over 400,000 SCM/d, under the Central field, including transportation infrastructure, and new exploration same price conditions of the fourth amendment. The fifth amendment also drilling of the block. Petroperú will also have the right to increase its WI waived the DOP and TOP thresholds for both parties, replacing them by in the block up to 50%, subject to GeoPark recovering its investments in the reasonable efforts to deliver and take, and giving GeoPark’s gas first priority block by certain agreed factors. over any third party supplies to Methanex. GeoPark has already been qualified as an Operator by Perupetro, the Peruvian petroleum licensing agency. Note 36 Note 35 Agreement with Methanex Strategic alliance with Tecpetrol in Brazil On 30 September 2013, the Company and Tecpetrol S.A. (“Tecpetrol”) announced the formation of a new strategic alliance to jointly identify, study and potentially acquire upstream oil and gas opportunities in Brazil, The Company has signed a long-term Gas Supply Contract with Methanex with a specific focus on the Parnaiba, Sao Francisco, Reconcavo, Potiguar in Chile, which expires in 2017. and Sergipe-Alagoas basins. In March 2012, the Company and Methanex signed a third addendum and Tecpetrol is the oil and gas subsidiary of the Techint Group (a multinational amendment to the Gas Supply Agreement to promote the development oilfield and steel conglomerate) with an extensive track-record as an of gas reserves. Through this new agreement, the Company completed oil and gas explorer and operator with its portfolio of assets currently in the drilling of five new gas wells during 2012. Methanex contributed to the cost of drilling the wells in order to improve the project economics. The Argentina, Peru, Colombia, Ecuador, Mexico, Bolivia, Venezuela and the United States, and with a current net production of over 85,000 barrels Company fulfilled all the commitments under this agreement. of oil equivalent per day. The Agreement also included monthly commitments for delivering certain At 31 December 2014, there is no accounting impact of the creation of volumes of gas and in case of failure, the Company could satisfy the obligation the alliance. through future deliveries without penalty during a period of three months. On 30 August 2013, the Company signed a fourth amendment to the Note 37 Methanex Gas Supply Agreement, pursuant to which the Company Oil industry situation and the impact on GeoPark’s operations committed, for a period of six months commencing 15 September, 2013, to deliver an increased volume, in a total amount of 400,000 SCM/d per As a consequence of oil price crisis which started in the second half month (subject to reduction for deliveries in excess of 200,000 SCM/d of 2014 (WTI and Brent, the main international oil price markers, fell more to Methanex or ENAP made between 29 April and 15 September, 2013), than 40% between September 2014 and February 2015), the Company has at an additional price per month of US$ 1.50 per mmbtu for volumes in undertaken a decisive cost cutting program to ensure its ability to both excess of 180,000 SCM/d, or an additional price per month of US$ 2.00 per maximize the work program and preserve its liquidity. The main decisions mmbtu in any month in which we were able to commit to deliver at least within the mentioned program for 2015 include: GeoPark 20F 227 GeoPark 20F 227 GeoPark 20F 227 - Reduction of its capital investment taking advantage of the discretionary The main assumptions taken into account for the impairment tests for the work programme. blocks below mentioned were: - 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 Latin American currencies (Colombian peso, Brazilian real, Chilean peso, Argentine peso and Peruvian sol), in connection with operating and structure scenarios”); - The table “Oil price scenarios” was based on WTI future price estimations; the Company adjusted this marker price on its model valuation to reflect costs established in local currencies. Note 38 the effective price applicable in each location (see Note 3 “Price risk”); - The model valuation was based on the expected cash flow approach; - The revenues were calculated linking price curves with levels of production according to certified reserves (see below table “Oil price scenarios”); Impairment test on Property, plant and equipment - The levels of production have been linked to certified risked 1P, 2P and 3P reserves (see Note 4); Considering the scenario described in Note 37, the Company has addressed - Production and structure costs were estimated considering internal the process of evaluating the recoverability of its fixed assets affected by historical data according to GeoPark’s own records and aligned to 2015 oil price drop. From an accounting point of view, this price drop constitutes approved budget; an impairment indicator according to IAS 36 and, consequently, it triggers - The capital expenditures were estimated considering the drilling campaign the need of assessing fair value of the assets involved against their carrying necessary to develop the certified reserves; amount. - The assets subject to impairment test are the ones classified as Oil and Gas properties and Production facilities and machinery; The Management of the Company considers as Cash Generating Unit (CGU) - The carrying amount subject to impairment test includes mineral interest; each of the blocks in which the Group has working or economic interests. - The income tax charges have considered future changes in the applicable The blocks with no material investment on fixed assets or with operations income tax rates (see Note 16). that are not linked to oil prices were not subject to impairment test. Table Oil price scenarios (*): Year 2015 2016 2017 2018 2019 2020 Over 2021 Amounts in US$ per Bbl Weighted market price used for the Low price (15%) Middle price (60%) High price (25%) impairment test 46,0 51,8 61,0 64,0 66,0 67,0 67,0 56,8 67,1 75,0 75,0 85,0 95,0 100,0 72,0 81,0 81,0 90,0 100,0 100,0 100,0 59,0 68,3 74,4 77,1 85,9 92,1 96,6 (*) The percentages indicated between brackets represent the Company estimation regarding each price scenario. 228 GeoPark 20F 228 GeoPark 20F 228 GeoPark 20F Summary for Chilean blocks impairment: Carrying amount Block name Flamenco Campanario Isla Norte Fell Working interest (US$ million) Impairment impact Projections year end Pre-tax discount rate 50% 50% 60% 100% 15,0 3,6 3,7 355,7 No No No No 2024 2024 2024 2029 10.5% 10.5% 10.5% 10.5% Summary for Colombian blocks impairment: Working interest (US$ million) Impairment impact Projections year end Pre-tax discount rate Carrying amount Block name Cuerva Block(1) Llanos 17 Block 100% 36.84% Yamu/Carupana Block 90% - 79.5% Llanos 34 Block Llanos 32 Block 45% 10% 68,0 6,0 17,0 77,0 9,0 Yes No No No No 2020 2016 2017 2022 2025 15.3% 15.3% 15.3% 15.3% 15.3% (1) The Company recognized an impairment loss in Cuerva Block that amounts to US$ 9,400,000; the carrying amount of the fixed assets related to Cuerva Block after deduction of impairment loss amounts to US$ 59,600,000. 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$ 13,000,000. Brazil segment did not present any impairment indicator as it produces mainly gas, which price is established by a supply agreement; Peru and Argentina segments have no associated assets subject to impairment. GeoPark 20F 229 GeoPark 20F 229 GeoPark 20F 229 Note 39 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 The following information is presented in accordance with ASC No. 932 that were incurred during each of the years ended as of 31 December 2014, “Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and 2013 and 2012. The acquisition of properties includes the cost of acquisition Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 of proved or unproved oil and gas properties. Exploration costs include in order to align the current estimation and disclosure requirements with geological and geophysical costs, costs necessary for retaining undeveloped the requirements set in the SEC final rules and interpretations, published on properties, drilling costs and exploratory well equipment. Development December 31, 2008. This information includes the Company’s oil and gas costs include drilling costs and equipment for developmental wells, production activities carried out in Chile, Colombia, Brazil and Argentina. the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves. Amounts in US$ '000 Year ended 31 December 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 Amounts in US$ '000 Year ended 31 December 2012 Acquisition of properties Proved Unproved Total property acquisition Exploration Development Total costs incurred Chile Colombia Argentina Brazil Total - - - 84,251 82,742 166,993 - - - 14,114 55,336 69,450 - - - (123) 126 3 112,646 - 112,646 12,004 1,052 125,702 112,646 - 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 Chile Colombia Argentina Total - - - 58,301 89,669 147,970 82,766 27,818 110,584 28,999 27,479 167,062 - - - (1,602) 499 (1,103) 82,766 27,818 110,584 85,698 117,647 313,929 (1) Includes capitalised amounts related to asset retirement obligations. 230 GeoPark 20F 230 GeoPark 20F 230 GeoPark 20F Table 2 - Capitalised costs related to oil and gas producing activities The following table presents the capitalized costs as at 31 December 2014, 2013 and 2012, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates. 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(1) 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 8,865 100,623 (4,951) 95,672 111,646 749,947 59,159 140,444 1,061,196 (285,585) 775,611 (1) Includes capitalised amounts related to asset retirement obligations and impairment loss in Colombia for US$ 9.4 million. 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(1) 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. Amounts in US$ '000 At 31 December 2012 Proved properties - Equipment, camps and other facilities - Mineral interest and wells(1) - Other uncompleted projects Unproved properties Gross capitalised costs Accumulated depreciation(1) Total net capitalised costs (1) Includes capitalised amounts related to asset retirement obligations. Chile Colombia Argentina Total 69,755 236,499 44,806 59,924 410,984 (98,161) 312,823 16,351 103,023 8,520 33,151 161,045 (20,917) 140,128 843 4,849 - 31 5,723 (5,414) 309 86,949 344,371 53,326 93,106 577,752 (124,492) 453,260 GeoPark 20F 231 GeoPark 20F 231 GeoPark 20F 231 Table 3 - Results of operations for oil and gas producing activities The breakdown of results of the operations shown below summarises revenues and expenses directly associated with oil and gas producing activities for the years ended 31 December 2014, 2013 and 2012. Income tax for the years presented was calculated utilizing the statutory tax rates. 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 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 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 Results of oil and gas operations 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 Results of oil and gas operations 232 GeoPark 20F 232 GeoPark 20F 232 GeoPark 20F Amounts in US$ '000 Year ended 31 December 2012 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 Results of oil and gas operations (1) Do not include Peru costs. (2) Represents accretion of ARO liability. Chile Colombia Argentina Total 149,927 99,501 1,050 250,478 (30,586) (7,088) (37,674) (22,080) (265) (28,120) 61,788 (9,268) 52,520 (35,069) (4,164) (39,233) (5,528) (803) (20,964) 32,973 (10,881) 22,092 151 (172) (21) (282) (194) (3,223) (2,670) 935 (1,735) (65,504) (11,424) (76,928) (27,890) (1,262) (52,307) 92,091 (19,214) 72,877 Table 4 - Reserve quantity information The Company estimates its reserves at least once a year. The Company’s Estimated oil and gas reserves Proved reserves represent estimated quantities of oil (including crude oil DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton prepared its proved oil and natural gas reserve and condensate) and natural gas, which available geological and engineering estimates in accordance with Rule 4-10 of Regulation S-X, promulgated by data demonstrates with reasonable certainty to be recoverable in the future the SEC, and in accordance with the oil and gas reserves disclosure provisions from known reservoirs under existing economic and operating conditions. of ASC 932 of the FASB Accounting Standards Codification (ASC) relating Proved developed reserves are proved reserves that can reasonably be to Extractive Activities-Oil and Gas (formerly SFAS no. 69 Disclosures about reserves estimation as of 31 December 2014, 2013 and 2012 was based on the expected to be recovered through existing wells with existing equipment Oil and Gas Producing Activities). and operating methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage Reserves engineering is a subjective process of estimation of hydrocarbon of development, quality and reliability of basic data, and production history. accumulation, which cannot be accurately measured, and the reserve The Company believes that its estimates of remaining proved recoverable estimation depends on the quality of available information and the interpretation and judgment of the engineers and geologists. Therefore, oil and gas reserve volumes are reasonable and such estimates have been the reserves estimations, as well as future production profiles, are often prepared in accordance with the SEC Modernization of Oil and Gas Reporting different than the quantities of hydrocarbons which are finally recovered. rules, which were issued by the SEC at the end of 2008. The accuracy of such estimations depends, in general, on the assumptions on which they are based. GeoPark 20F 233 GeoPark 20F 233 GeoPark 20F 233 The estimated GeoPark net proved reserves for the properties evaluated as of 31 December 2014, 2013 and 2012 are summarised as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf): Net proved developed Chile(1) Colombia(2) Brazil(3) Total consolidated Net proved undeveloped Chile(4) Colombia(5) Brazil(5) Total consolidated Total proved reserves As of 31 December 2014 As of 31 December 2013 As of 31 December 2012 Oil and Oil and Oil and condensate Natural gas condensate Natural gas condensate Natural gas (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) (MMcf) 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 2,104.8 2,008.6 - 4,113.4 3,153.3 4,618.4 - 7,771.7 11,885.1 12,768.0 - - 12,768.0 16,813.0 - - 16,813.0 29,581.0 (1) Fell Block accounts for 92% of the reserves (100% in 2013 and 2012) (LGI owns a 20% interest) and Flamenco Block accounts for 8% (LGI owns 31.2% interest). (2) Llanos 34 Block and Cuerva Block account for 79% and 17% (58% and 36% in 2013 and 31% and 53% in 2012) 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 96% of the reserves (100% in 2013 and 2012) (LGI owns a 20% interest), Flamenco Block accounts for 3% and Isla Norte accounts for 1% (LGI owns 31.2% interest). (5) Llanos 34 Block and Cuerva Block account for 91% and 7% (74% and 23% in 2013 and 72% and 25% in 2012) of the proved undeveloped reserves, respectively (LGI owns a 20% interest). 234 GeoPark 20F 234 GeoPark 20F 234 GeoPark 20F Chile 5,254.1 (1,250.8) 2,670.0 - (1,415.2) 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 Colombia Brazil - - - 7,522.8 (895.8) 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 - - - - - - - - - - - - 150.0 (20.0) 130.0 Total 5,254.1 (1,250.8) 2,670.0 7,522.8 (2,311.0) 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 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 2011 Increase (decrease) attributable to: Revisions(1) Extensions and discoveries Purchases of minerals in place Production Reserves as of 31 December 2012 Increase (decrease) attributable to: Revisions Extensions and discoveries(2) Production Reserves as of 31 December 2013 Increase (decrease) attributable to: Revisions(3) Extensions and discoveries(4) Purchases of minerals in place (Note 34) Production Reserves as of 31 December 2014 (1) The revisions are mainly related to condensate from the reduced gas and two fields in the Fell Block (Copihue and Guanaco) where there were reductions in proved recovery based on performance. (2) Mainly due to 2013 discoveries in Llanos 34 (Taro Taro, Tigana and Tigana Sur) and Yamú (Potrillo). (3) 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. (4) 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. GeoPark 20F 235 GeoPark 20F 235 GeoPark 20F 235 Net proved reserves (developed and undeveloped) of natural gas: Millions of cubic feet Reserves as of 31 December 2011 Increase (decrease) attributable to: Revisions(1) Extensions and discoveries Purchases Production Reserves as of 31 December 2012 Increase (decrease) attributable to: Revisions(2) Extensions and discoveries Production Reserves as of 31 December 2013 Increase (decrease) attributable to: Revisions(3) Extensions and discoveries(4) Purchases of minerals in place (Note 34) Production Reserves as of 31 December 2014 Chile 57,157.0 (21,860.0) 2,256.0 - (7,972.0) 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 Brazil - - - - - - - - - - - - 47,680.0 (7,216.0) 40,464.0 Total 57,157.0 (21,860.0) 2,256.0 - (7,972.0) 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 (1) The revisions are mainly due to the effect of having reduced the (3) The revisions are mainly due to Chercán Field development in TdF Block Company’s future gas production profile in Chile because of expected and gas and associated gas performance/development in Fields of Fell Block. reduced deliveries to the Methanex plant. This causes a significant (4) Mainly due to the Ache Field discovery and the associated gas from portion of the gas reserves to be produced below an economic level later Konawentru extensions wells. in the productive life of the Fell Block and after the expiration of the Methanex Gas Supplies Agreement. Revisions refer to changes in interpretation of discovered accumulations (2) The revisions are mainly due to adjustments in the Fell Block as a and some technical/logistical needs in the area obliged to modify response to a workover in Monte Aymond field, and associated gas from the timing and development plan of certain fields under appraisal and drilling campaigns in Konawentru and Yagán Norte fields. development phases. 236 GeoPark 20F 236 GeoPark 20F 236 GeoPark 20F Table 6 - Standardized measure of discounted future net cash flows related to This standardized measure is not intended to be and should not be interpreted proved oil and gas reserves as an estimate of the market value of the Company’s reserves. The purpose The following table discloses estimated future net cash flows from future of this information is to give standardized data to help the users of the financial production of proved developed and undeveloped reserves of crude oil, statements to compare different companies and make certain projections. condensate and natural gas. As prescribed by SEC Modernization of It is important to point out that this information does not include, among other Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards items, the effect of future changes in prices, costs and tax rates, which past Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS experience indicates that are likely to occur, as well as the effect of future cash no. 69 Disclosures about Oil and Gas Producing Activities), such future net cash flows from reserves which have not yet been classified as proved reserves, flows were estimated using the average first day- of-the-month price during of a discount factor more representative of the value of money over the the 12-month period for 2014, 2013 and 2012 and using a 10% annual discount lapse of time and of the risks inherent to the production of oil and gas. These factor. Future development and abandonment costs include estimated future changes may have a significant impact on the future net cash flows drilling costs, development and exploitation installations and abandonment disclosed below. For all these reasons, this information does not necessarily costs. These future development costs were estimated based on evaluations indicate the perception the Company has on the discounted future net cash made by the Company. The future income tax was calculated by applying flows derived from the reserves of hydrocarbons. 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 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 At 31 December 2012 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows Chile Colombia Brazil Total 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) 163,860 568,647 (135,525) (149,100) (44,218) 239,804 (37,355) 202,449 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) 173,792 491,578 (181,780) (45,966) (98,773) 165,059 (31,414) 133,645 307,535 (124,265) (19,965) (19,566) 143,739 (31,594) 112,145 - - - - - - - - - - - - - - 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 1,060,225 (317,305) (195,066) (142,991) 404,863 (68,769) 336,094 GeoPark 20F 237 GeoPark 20F 237 GeoPark 20F 237 Chile 285,603 (110,331) 45,100 (73,255) 108,768 57,055 (174,757) - 23,250 36,215 4,801 202,449 (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 Colombia - (10,015) - - - - - 143,660 - - - 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 Brazil - - - - - - - - - - - - - - - - - - - - - (39,414) 7,409 (22,143) - 1,340 1,559 4,156 142,423 16,815 112,145 Total 285,603 (120,346) 45,100 (73,255) 108,768 57,055 (174,757) 143,660 23,250 36,215 4,801 336,094 (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 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 2011 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Purchase of minerals in place Net changes in income taxes Accretion of discount Other changes 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 238 GeoPark 20F 238 GeoPark 20F 238 GeoPark 20F Exhibit 12.1 Exhibit 12.2 CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER PURSUANT TO CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, James F. Park, certify that: I, Andrés Ocampo, certify that: 1. I have reviewed this annual report on Form 20-F of GeoPark Limited; 1. I have reviewed this annual report on Form 20-F of GeoPark Limited; 2. Based on my knowledge, this report does not contain any untrue statement 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company financial condition, results of operations and cash flows of the company as of, as of, and for, the periods presented in this report; and for, the periods presented in this report; 4. The company’s other certifying officer(s) and I are responsible for 4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the company and have: for the company and have: a. Designed such disclosure controls and procedures, or caused such a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, disclosure controls and procedures to be designed under our supervision, to to ensure that material information relating to the company, including its ensure that material information relating to the company, including consolidated subsidiaries, is made known to us by others within those its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the company’s disclosure controls and c. Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the effectiveness of the disclosure controls and procedures, as of the end of period covered by this report based on such evaluation; and the period covered by this report based on such evaluation; and d. Disclosed d. Disclosed in this report any change in the company’s internal control over in this report any change in the company’s internal control over financial financial reporting that occurred during the period covered by the annual reporting that occurred during the period covered by the annual report that report that has materially affected, or is reasonably likely to materially affect, has materially affected, or is reasonably likely to materially affect, the the company’s internal control over financial reporting; and 5. The company’s other certifying officer(s) and I have disclosed, based on company’s internal control over financial reporting; and 5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, our most recent evaluation of internal control over financial reporting, to the to the company’s auditors and the audit committee of the company’s board company’s auditors and the audit committee of the company’s board of of directors (or persons performing the equivalent functions): directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, likely to adversely affect the company’s ability to record, process, summarize summarize and report financial information; and and report financial information; and b. Any fraud, whether or not material, that involves management or other b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over employees who have a significant role in the company’s internal control over financial reporting. Date: April 30, 2015 /s/ James F. Park James F. Park Chief Executive Officer (Principal Executive Officer) financial reporting. Date: April 30, 2015 /s/ Andrés Ocampo Andrés Ocampo Chief Financial Officer (Principal Financial Officer) GeoPark 20F 239 GeoPark 20F 239 GeoPark 20F 239 Exhibit 13.1 Exhibit 13.2 CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 The certification set forth below is being submitted in connection with the The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the fiscal year ended December 31, 2014 (the “Report”), I, James F. Park, certify fiscal year ended December 31, 2014 (the “Report”), I, Andrés Ocampo, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: 1. the Report fully complies with the requirements of Section 13(a) or 15(d) 1. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and of the Securities Exchange Act of 1934; and 2. the information contained in the Report fairly presents, in all material 2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. respects, the financial condition and results of operations of the Company. Date: April 30, 2015 /s/ James F. Park James F. Park Chief Executive Officer (Principal Executive Officer) Date: April 30, 2015 /s/ Andrés Ocampo Andrés Ocampo Chief Financial Officer (Principal Financial Officer) 240 GeoPark 20F GeoPark 20F 241 242 GeoPark 20F Designed by: Chiappini + Becker Tel. +54 11 4314 7774 www.ch-b.com Photographer: Diego Dicarlo, Geologist GeoPark 20F 243  Directors, Secretary & Advisors Gerald E. O’Shaughnessy (Chairman) James F. 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) 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 7550000 Las Condes, Santiago Chile | + 56 2 242 9600 Pedro Aylwin Davis Polk & Wardwell LLP 450 Lexington Avenue New York, NY 10017 USA Cox Hallett Wilkinson Cumberland House 9th Floor, 1 Victoria Street Hamilton HM11 - Bermuda P.O. Box HM 1561 Hamilton HMFX - Bermuda Price Waterhouse & Co. S.R.L. Bouchard 557, 8th Floor Buenos Aires Argentina DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 USA Computershare Investor Services 480 Washington Blvd. Jersey City, NJ 07310 USA Directors Registered Office Corporate Offices Director of Legal and Governance and Corporate Secretary Counsel to the Company as to New York Law Solicitors to the Company as to Bermuda Law Independent Auditors Petroleum Consultant Registrar & Transfer Agent 244 Peter Ryalls | Non-Executive Director Mr. Ryalls has been a member of our board of directors since April 2006. He holds a master’s degree in petroleum engineering from imperial College in London. Mr. Ryalls has worked for schlumberger Limited in Angola, Gabon and Nigeria, as well as for Mobil North sea. He has also worked for Unocal Corporation where he held increasingly senior positions, including as Managing director 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. Bedingfield is a qualified sEC financial expert and has assumed the role of Chairman of GeoPark’s Audit Committee. Until his retirement in June 2013, Mr. Bedingfield 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, 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. He also served on the Board of Governors of the Congressional Country Club in Bethesda, Maryland. 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 studies. 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, 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 has lived in Argentina and Chile since 2002. Board of directors Gerald E. O’Shaughnessy | Chairman Mr. O’shaughnessy has been our Chairman and a member of our board of directors since he co-founded the company in 2002. Following his graduation from the University of Notre dame with degrees in government (1970) and law (1973), Mr. O’shaughnessy was engaged in the practice of law in Minnesota. Mr. O’shaughnessy has been active in the oil and gas business over his 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 in Russia during the 1990s. in 2010 Mr. O’shaughnessy founded Lario Logistics, a U.s. midstream company which owns and operates the Bakken Oil Express, serving oil producers and service providers in the Bakken Oil play. in addition to his oil and gas activities Mr. O’shaughnessy is also engaged in investments in banking, wealth management, desktop software, computer and network security, and green clean technology. Over the past 25 years, Mr. O’shaughnessy has also served on a number of non-profit boards of directors, including the Board of Economic Advisors to the Governor of Kansas, the i.A. O’shaughnessy Family Foundation, the Wichita Collegiate school, the institute for Humane studies, The East West institute and The Bill of Rights institute. Mr. O’shaughnessy 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 GeoPark 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 of Aylwin 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. Mr. Aylwin is also a member of the board of directors of Egeda España. Carlos Gulisano | Non-Executive Director Mr. Gulisano has been a member of our board of directors since June 2010. dr. Gulisano holds a bachelor’s degree in geology, a post-graduate degree in petroleum engineering and a Phd in geology from the University of Buenos Aires and has authored or co-authored over 40 technical papers. He is a former adjunct professor at the Universidad del sur, a former thesis director at the University of La Plata, and a former scholarship director at 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 30 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. At santana 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 cofounded 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 Hidroeléctrica Totoral. Over the last few years he has been a board member of several companies, including Quintec, Enaex, CTi and Frimetal. ANNUAL REPORT 2014 WWW.GEO-PARK.COM 

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