Geopark Ltd
Annual Report 2013

Plain-text annual report

annual rEport 2013 3 1 0 2 t r o p E r l a u n n a k r a P o e G EXplorEr opErator consolidator contEnts 2 chairman / cEo letter 12 2013 performance 14 our strengths 16 18 our approach Form 20-F 232 Board of directors Oil and Gas Production Oil and Gas Reserves BottoM linE 18 16 14 12 10 8 6 4 2 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 80 70 60 50 40 30 20 10 0 e o b M M n i 2009 2010 2011 2012 2013 2013 pro forma 2009 2010 2011 2012 2013 2013 pro forma oil and condensate Gas 2p oil 2p Gas Total Revenues Adjusted EBITDA1 400 350 300 250 200 150 100 $ s u M M n i 50 0 200 150 100 50 0 $ s u f o M M n i 2009 2010 2011 2012 2013 2013 pro forma 2009 2010 2011 2012 2013 2013 pro forma oil and condensate Gas (1) see definition of adjusted EBitda on page 22 of this annual report dear shareholders, We are pleased to report that Geopark had another record year in despite our on-the-ground progress, our share price performance 2013 – with more oil and gas found and produced, our strongest was down approximately 4.2% for the year with very little trading financial results ever, an increase in our underlying value per share, a activity. to address this situation, we made an important transition in strengthened organization, and strategic expansion into a new early 2014 from the london aiM Market to the new York stock region to continue opening future opportunities. Geopark is now Exchange (nYsE) to reach a wider audience of investors and raise uniquely positioned in latin america with a self-funding platform additional funds (approximately $100 million) for expansion. consisting of 29 hydrocarbon blocks covering 1.9 million acres in 10 consistent with our move to the nYsE, we also increased investment proven hydrocarbon basins in 4 countries (chile, colombia, Brazil in our shareholder reporting and communication capacities, and argentina) with a rich mix of production, development, including an ongoing 2014 initiative to implement sap throughout exploration and unconventional resource projects – and the team our businesses. to make it work. Geopark is a company that started from ‘scratch’ in 2002 and our in 2013, and for the seventh consecutive year, our key performance consistent growth to date is a reflection of a systematic approach. measurements (excluding figures from our new Brazil assets) it means we have been able to continuously increase our production recorded important gains: oil and gas production up 20%, reserves at the same time continuously increasing our reserves. it means up 8% and adjusted EBitda up 38% (with revenues up 35%). we have been able to improve our operating and capital cost additionally, our net income increased by 89%, our netback per boe efficiencies, increase our cash flows, and use our capital wisely to produced increased by 9% and we had $121 million in cash at expand the business. it means we have been able to create a solid year-end. again, growth came from the drill bit with 39 new oil and supportive base that allows us to exploit the opportunities around gas wells drilled, with a success rate of 74% and the discovery of us. it means we have been able to build a strong and capable seven new oil and gas fields. team that is prepared to take Geopark into the future. it means we are in good shape for 2014 and beyond. We also expanded our business into our fourth country in latin america by entering Brazil, one of the world’s highest-potential hydrocarbon regions. including our new Brazil assets (agreed on in strategic context 2013 and closed in 2014), our 2013 pro forma figures for total oil and gas production increased to an average of 17,098 boepd, our proven For our new shareholders joining us following our move to the and probable reserves (prMs) grew to 70.2 million boe and our new York stock Exchange, we feel it may be helpful to review some revenues rose to $387 million with an adjusted EBitda of $198 of the core principles we have applied in building Geopark. million. With respect to funding, we accessed the international debt capital markets in early 2013 and successfully closed a $300 million our objective in founding Geopark was to create value by building (7 year) bond, which was substantially over-subscribed. the leading latin american upstream independent oil and gas significantly, our underlying economic value per share grew last caring company with the best ‘shareholder value-adding’ oil and company. By this, we mean an action-oriented, persistent, aware and year. one internal measurement (the npV10 of our certified 3p gas assets. reserves, adjusted by net debt and minority interests, and divided by the number of outstanding shares), indicates our oil and gas asset We believe the energy business – specifically the upstream oil and value per share increased by approximately 20% from 2012 to 2013. gas industry – is one of the most exciting, necessary, and (this is a relative performance measure that does not include economically-rewarding businesses today. no undertaking or society values for our exploration resources and our expanded inventory can advance without the supply of energy, and energy remains the of drilling opportunities.) critical element in allowing people to better their lives. Much of the 2 annual report 2013 05 annual report 2013 lEttEr to sHarEHoldErs annual report 2013 3 world still lacks adequate energy supplies for the most basic needs independent companies. (the us is home to over 6,000 independent and demand is continually increasing. although new exciting oil and gas operators, whereas latin america, an area substantially technologies and sources are being developed, oil and gas is the larger and with greater resource potential, has only a few handfuls of most reliable energy source and will be required to support independents taking advantage of available opportunities.) in over half of our planet’s continuous and rising energy needs far into contrast to many areas of the world, the environment and resources this century. for operating and funding a business are welcoming and increasingly more feasible. Furthermore, numerous good oil and gas We believe the best places for us to find and develop hydrocarbons assets in latin america are available, undervalued and at very are in areas around the world where oil and gas have already been attractive prices right now (particularly compared to north america). discovered, but which for economic, technical, funding or other reasons have been inadequately developed or prematurely Geopark has been conservatively built for the long term. We did not abandoned. these projects have proven hydrocarbon systems, start with a short term ‘exit strategy’ in mind, and do not see this as valuable technical information, existing infrastructure, and, in many an effective approach in building a team and business. our approach cases, unexploited low-risk exploration and re-development required patience in the beginning in order to create the foundation opportunities. By applying new technology and investment, creating to put us solidly ‘in the game’, but has enabled us to now have the stable markets and better economic conditions, and/or more chance to grab the bigger prizes. efficient operations, a neglected or forgotten asset can be converted into an attractive economic project. Work in these areas also Gerry and i, and our management team, have a substantial part frequently opens up exciting new hydrocarbon resources in new of our net worth invested in Geopark. neither Gerry nor i have ever geological play-types and formations. sold a share of Geopark stock. in fact, we have been stock buyers over time (including in the nYsE ipo). We have no special class We are focused on latin america because of the abundance of these of stock or arrangements that benefit us differently from any other types of opportunities throughout the region. latin america ranks shareholder other than our salaries and stock performance incentive as one of the highest potential hydrocarbon resource regions in the programs. the entire Geopark team (100% of our employees have world and its economies are thirsty for new energy. Historically, received Geopark share awards) is solidly aligned with all of it has been dominated by larger major and national oil companies, our shareholders to build real and enduring value for every share with the presence of only a modest number of more-agile of Geopark. 4 annual report 2013 lEttEr to sHarEHoldErs opportunity Enhancement and risk diversification By its very nature, the upstream oil and gas business represents the characteristics of a local company. our pride and care in how we act undertaking of risk in search of significant rewards. to succeed, an and perform in our home regions are key elements of our success. oil and gas company must effectively identify and manage the existing risks and uncertainties to ensure capturing the available these generally decentralized businesses are further enhanced by rewards. We believe this to be one of Geopark’s key capabilities; and being tied together by an overall corporate organization, which our year over year track record is evidence of our success in improves efficiencies, reduces costs with operational and financial effectively balancing risk among the subsurface, geological, funding, synergies, controls quality, and can more effectively raise capital for organizational, market, price, partner, shareholder, regulatory and our projects. it also is a source for new technologies and ideas. For political environments. For example, during the difficult global example, our team introduced a new geological play-type to the financial crisis of 2008/9, which caused many to retreat, Geopark was llanos Basin in colombia (an area that has been explored for more able to bring all the elements of our business together to achieve than 75 years) that resulted in multiple new oil field discoveries, and continuous growth. new oil technology to the Magallanes Basin in chile that successfully increased production and reserves. We believe the best results in the upstream business are achieved with a larger scale portfolio approach with multiple attractive importantly, through effective and controlled capital allocation, our projects in multiple regions managed by talented oil and gas teams. businesses can also beneficially compete with each other thereby this diversification reflects both a defensive and offensive approach. allowing our resources to flow to the highest performing projects. it is protective of any downside because the collective strength of our projects limits the negative impact of any underperforming We believe this business approach makes Geopark a more attractive asset. it also has an exciting multiplier effect on the potential upside investment vehicle for all our shareholders; with a strong foundation because of the increased number of opportunities independently to minimize any downside, a big upside through multiple marching ahead. growth opportunities, and an overall organizational system to more efficiently run and grow the individual businesses. our country businesses are managed by experienced local professionals and teams with high reputations. they know both the specific subsurface rocks and conditions and the above-ground operating and business environments in each region and give us the annual report 2013 5 annual report & 20F Form 04 capabilities Businesses: review and outlook our experience in the oil and gas business has repeatedly Geopark’s approach has resulted in an expanding business in each demonstrated the need for good people with commitment and real country, managed by good teams, with supporting production and oil and gas know-how. We believe in and have experienced the cash flow, and inventories of attractive new growth projects. We are amazing capacity of people to excel in an environment of expanding aggressively investing to grow our businesses and, in 2014, have opportunity and trust. our efforts to create such a team have far embarked on a $220-250 million work program – funded by our own exceeded our expectations and Geopark is blessed to have an cash flows – targeting a strong 15-20% production growth rate. this incredible group of men and women who truly work day and night program (which does not include expected new project acquisitions) to make us better in every way. our results speak to the daily heroics consists of drilling of 50-60 new wells, new seismic surveys and (mostly unseen) by our team that keep us together and have new facility construction; and is balanced between exploration (40%) moved us consistently closer towards our goals. and development (60%) and spread approximately between chile (62%), colombia (33%) and Brazil (5%). By design, our work program our record of delivery is based on three fundamental and distinct is largely discretionary and can be adapted to accommodate any skill sets – as Explorers, operators and consolidators – which we new opportunities or needs. deem critical for enduring success in the oil and gas business. our team has consistently demonstrated the science and creativity to chile Business find hydrocarbons in the subsurface, but also the muscle and experience to get the oil and gas out of the ground and profitably to Geopark first proved our business model in chile where we became market. our attractive asset portfolio is evidence of our ability to chile’s first private oil and gas producer. From a ‘flat-footed’ start-up acquire good projects in the right basins in the right countries with in 2006, we built a solid business currently with production of the right partners and at the right price. approximately 7,000 boepd, 2p (prMs) reserves of approximately 45 today, we have over 400 employees – from chile, colombia, Brazil prospective acres. in 2011, lG (the Korean conglomerate) acquired and argentina – each of whom joined Geopark with the purpose a 20% interest in our chile business for $148 million, plus other of building a unique and special company that is prepared to benefits, thereby giving a value to our chile business alone of million boe and 6 blocks with approximately 1.0 million highly- handle challenges and seize opportunities. as a quickly growing approximately $740 million. company, we have repeatedly seen individuals step-up to the new responsibilities presented – and we have a deep and powerful in 2013 in the Fell Block, we continued to increase oil production (up leadership team taking Geopark to the next level. 14%) from our successful drilling program in the tobifera formation, a volcaniclastic geological formation, formerly considered non- the international upstream oil and gas business is not for the prospective. today, over 60% of our chile production is from the fainthearted or easily discouraged. time-after-time, the Geopark tobifera formation and we are further developing the methodology team has been able to push ahead to find solutions where often to most effectively exploit this exciting opportunity, including the others have given-up or failed. this is the engine and fire of our application of electrical submersible pumps. the Fell Block, which growth and the true long term intangible value of our company. covers approximately 370,000 acres and currently produces from We are immensely grateful to all these men and women for approximately 20 oil and gas fields (all developed by Geopark), their professionalism, discipline, unity and heart. continues to hold new opportunities from identified but undrilled prospects and from the exploration of new geological formations. in 2014, we expect to drill another 17-19 wells to increase production and reserves. the Fell Block also contains an attractive thick shale formation over a large area (180,000 acres) that has tested oil and contains a large unconventional oil resource opportunity that is currently being evaluated. 6 annual report 2013 lEttEr to sHarEHoldErs annual report 2013 7 capabilities our experience in the oil and gas business has repeatedly of building a unique and special company that is prepared to handle challenges and seize opportunities. as a quickly growing company, we have repeatedly seen individuals step-up to the new demonstrated the need for good people with commitment and real responsibilities presented – and we have a deep and powerful oil and gas know-how. We believe in and have experienced the leadership team taking Geopark to the next level. amazing capacity of people to excel in an environment of expanding opportunity and trust. our efforts to create such a team have far exceeded our expectations and Geopark is blessed to have an incredible group of men and women who truly work day and night to make us better in every way. our results speak to the daily heroics (mostly unseen) by our team that keep us together and have moved us consistently closer towards our goals. our record of delivery is based on three fundamental and distinct skill sets – as Explorers, operators and consolidators – which we deem critical for enduring success in the oil and gas business. our team has consistently demonstrated the science and creativity to find hydrocarbons in the subsurface, but also the muscle and experience to get the oil and gas out of the ground and profitably to market. our attractive asset portfolio is evidence of our ability to acquire good projects in the right basins in the right countries with the right partners and at the right price. today, we have over 400 employees – from chile, colombia, Brazil and argentina – each of whom joined Geopark with the purpose the international upstream oil and gas business is not for the fainthearted or easily discouraged. time-after-time, the Geopark team has been able to push ahead to find solutions where 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 are immensely grateful to all these men and women for their professionalism, discipline, unity and heart. Businesses: review and outlook Geopark’s approach has resulted in an expanding business in each country, managed by good teams, with supporting production and cash flow, and inventories of attractive new growth projects. We are aggressively investing to grow our businesses and, in 2014, have embarked on a $220-250 million work program – funded by our own cash flows – targeting a strong 15-20% production growth rate. this program (which does not include expected new project acquisitions) consists of drilling of 50-60 new wells, new seismic surveys and new facility construction; and is balanced between exploration (40%) 8 annual report 2013 lEttEr to sHarEHoldErs lEttEr to sHarEHoldErs and development (60%) and spread approximately between chile (62%), colombia (33%) and Brazil (5%). By design, our work program is largely discretionary and can be adapted to accommodate any in 2014, we expect to drill another 17-19 wells to increase production new opportunities or needs. and reserves. the Fell Block also contains an attractive thick shale chile Business formation over a large area (180,000 acres) that has tested oil and contains a large unconventional oil resource opportunity that is currently being evaluated. Geopark first proved our business model in chile where we became chile’s first private oil and gas producer. From a ‘flat-footed’ start-up Following our acquisition of three new blocks in the island of in 2006, we built a solid business currently with production of tierra del Fuego in 2012 across the Magellan straits, our team moved approximately 7,000 boepd, 2p (prMs) reserves of approximately 45 efficiently and swiftly to complete a 1,500 sq km seismic campaign, million boe and 6 blocks with approximately 1.0 million highly- begin drilling on the Flamenco Block, and successfully discovering prospective acres. in 2011, lG (the Korean conglomerate) acquired and putting the new chercan field into production in 2013. these a 20% interest in our chile business for $148 million, plus other blocks cover an area of approximately 460,000 acres and represent a benefits, thereby giving a value to our chile business alone of similar geological play, with targets in the tobifera, springhill and approximately $740 million. tertiary formations, as the successful Fell Block. our geological and geophysical team has identified 25-30 new attractive leads and in 2013 in the Fell Block, we continued to increase oil production (up prospects, and a 15-17 exploration and development well drilling 14%) from our successful drilling program in the tobifera formation, program is now underway for 2014. a volcaniclastic geological formation, formerly considered non- prospective. today, over 60% of our chile production is from the colombia Business tobifera formation and we are further developing the methodology to most effectively exploit this exciting opportunity, including the after patiently waiting for asset prices to settle down from an application of electrical submersible pumps. the Fell Block, which over-inflated oil and gas asset market in 2010 and 2011, we found a covers approximately 370,000 acres and currently produces from window of opportunity in early 2012 to enter colombia. Following approximately 20 oil and gas fields (all developed by Geopark), continues to hold new opportunities from identified but undrilled prospects and from the exploration of new geological formations. annual report 2013 9 We are also making efforts to establish a new platform in peru; which interest partner. We also target relationships with the national has major hydrocarbon resources and is making a concentrated oil companies where we operate, such as with Enap in chile and effort to become more accessible to and benefit from oil and gas petrobras in Brazil. investment activities similar to its neighbors (such as colombia). We are also beginning to evaluate opportunities in Mexico; critical to the success of any new project is to conduct a thorough which has always represented a big prize, but where it has been technical and economic analysis prior to acquiring any new asset. difficult for companies to acquire direct holdings. current rapidly We make sure we understand the project, its risks and its value – advancing regulatory reforms may finally open the door for and we buy right. no team can turn a faulty or overpriced project private companies to access some of Mexico’s highly attractive into a good business. Following an intensive geological, geophysical, hydrocarbon assets – many of which would be an excellent fit for engineering, operational, legal and financial analyses and due Geopark’s approach and skillset. diligence, we perform a detailed discounted cash flow (dcF) valuation. We also consider the option value or strategic benefits of With our overall growth targets and portfolio approach, new project a project when entering a new region. We do not buy assets on acquisitions are an important part of our business. our acquisition simplified ‘$ per barrel’ metrics which we believe do not properly efforts begin with a technical approach to define the hydrocarbon account for multiple factors (including technical, cost, tax, and time) basins where our geological and engineering teams identify that impact the economics of oil and gas projects. We also avoid an attractive potential. after screening for political risks, our new markets or ‘bubbles’ when assets are over-priced. business teams proactively ‘scratch and dig’ to locate interests or opportunities within those areas and to establish a position. it is a long term and continuous effort and we have been building an culture attractive inventory of new projects in the region over the last ten years, aided by our team’s 25+ year experience in latin america. ‘creating Value and Giving Back’ is our motto and represents Geopark’s market-based approach to align our business objectives our focus is always to build a larger scale balanced portfolio that with our core values and responsibilities. our in-house designed includes lower-risk short term cash flow generating properties, mid program, titled s.p.E.E.d., targets and integrates the critical elements term medium-risk development projects, and longer term higher- – safety, prosperity, Employees, Environment and community risk big upside projects. this permits steady secure growth with development – necessary to make our total business plan work. an opportunity for accelerated high growth ‘home-runs’ from the Without succeeding equally in each of these interdependent areas, bigger projects. our overall success and ambitions cannot be realized. this is important in every country where we operate, and we make every Good oil and gas partners are a key element of our new business effort to achieve the most effective governance, full compliance efforts and we like to balance our acquisition risk by including and consistent transparency with all relevant authorities. not only experienced partners in new projects. We have developed a long does this allow us to be a more successful business enterprise over term strategic alliance with lG to build a portfolio of upstream assets the long term, it reflects our pride in carrying out an important across latin america and with tecpetrol (the affiliate of techint) to mission in the right way. the men and women of Geopark care acquire new projects in Brazil. the international Finance corporation passionately about how our company acts – both internally (iFc) of the World Bank is a long term principal shareholder of (and and externally – and we all consider our culture to be our core asset sometimes lender to) Geopark, and has also joined us as a working and the prime source of our past success and future opportunity. 10 annual report 2013 lEttEr to sHarEHoldErs lEttEr to sHarEHoldErs the world is continuously moving in a more regulated direction and, our thanks and appreciation to our shareholders – long term with higher expectations, and to be able to operate in this new and new – who have joined us, believed in our project and environment is a fundamental part of business today. We believe supported our efforts. as always, your comments and that Geopark’s ability to meet these challenges and perform to recommendations are welcome and appreciated. We invite you to or beyond these ever increasing standards represents a competitive always visit us in the field or at any of our offices to better know advantage for the future. For example, the manner of, results from, us and learn first-hand how we work. and impact on the communities of our overall work in chile provided the rationale and support for the government and regional Following this letter, please find the Form 20-F annual report which community to allow us to successfully expand our project into new provides a more comprehensive review of our activities during 2013, areas. it can also be meaningful and fun, such as with our full with further details and explanations and more exact clarifications scholarships targeting young women, in the local communities near of some of the subjects and figures generally presented in this letter. our field operations, to enter into and study the sciences. (please also refer to the 20-F for definitions of “adjusted EBitda” the iFc of the World Bank, our long time shareholder, has been a constructive force in helping us operate and manage our business in We look forward to delivering and reporting to you on our used herein.) consideration of the environment and communities around us. results in 2014. the iFc further assists us by carrying out annual audits and physical site visits of both our regulatory compliance and best-practices sincerely, approach. thank You again, our thanks to all the men and women in Geopark for the Gerald E. O’Shaughnessy company you have created, for your trust of each other and for the chairman unique spirit which propels us forward. our gratitude especially extends to our relentlessly supportive families who have all contributed mightily to who we have become and what we will do next. our thanks to our Board of directors for your guidance through the year and your continuous efforts in helping Geopark improve and grow. in addition to significant corporate governance responsibilities, Geopark’s Board members have spent substantial time working directly with our teams, sharing their experience, and traveling to our different operations. James F. Park chief Executive officer annual report 2013 11 2013 pErForMancE Key Operational Results Key Financial Results Key Strategic Results Oil and Gas Production Revenues Up 35%: Brazil Production Acquisition: Up 20%: average oil and gas total revenues increased acquisition of 10% interest in production increased to 13,517 to $338.4 million. pro forma, Manati Field, largest producing boepd. pro forma, annual revenues increased to gas field in Brazil, in May 2013 2013 production increased to $386.9 million (closed in March 2014) 17,098 boepd Adjusted EBITDA up 38%: Brazil Exploration Blocks: 74% Drilling Success: adjusted EBitda increased to nine new hydrocarbon blocks 39 new wells drilled (balance $167.3 million. pro forma, awarded in rounds 11 and of exploration, appraisal adjusted EBitda increased 12 in Brazil in the sergipe and development) with 7 new to $197.0 million alagoas, parnaiba, potiguar and oil and gas field discoveries reconcavo Basins (one block Adjusted EBITDA per from round 12 subject to 2P Reserves Up 8%: boe up 9%: adjusted EBitda anp approval) deGoyler and Mcnaughton per boe increased to $33.9 certified 2p prMs reserves grew Funding: to 61.6 mmboe, with reserve Cash Resources: 2020 Bond issued for $300 replacement of 199%. $121.1 million at year end million in February 2013 to including the Manati Field replace existing debt (Brazil) acquisition, 2p prMs Capital Expenditures: and finance organic and reserves increased by 23% capital expenditures amounted inorganic growth to 70.2 mmboe to $228.0 million including Seismic Operations: and $82.3 million invested strategic alliance with $145.7 million invested in chile New Partnership: approximately 1,350 sqkm in colombia of 3d seismic acquired in chile and colombia Net Income up 89%: Tierra del Fuego Start-Up: seismic, drilling and production profit for the year increased to $34.9 million tecpetrol for new upstream oil and gas projects in Brazil start-up * pro forma 12 annual report 2013 2009200820072006 Oil Gas 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 0 ) d / e o b M ( n o i t c u d o r p y l i a d e g a r e v a annual report 2013 13 2010201120122013* our strEnGtHs KNOw-HOw ASSETS TRACK RECORD strong team, capabilities, approach and culture. diversified risk-Balanced asset Base with proven Value, scale and upside. consistent operational and Financial Growth / ability to unlock Value from assets. CAPITAl GROwTH PlATFORm supporting cash Flow, access to Funding and strategic partners. High-impact portfolio of organic and new project opportunities. 14 annual report 2013 C OlOmB I A P E R U p a c iFi c o cEa n C H IlE B R A Z Il A R G E N T I N A a t l a n t i c o cEa n Asset Types production development Exploration unconventional new acquisition targets annual report 2013 15 our approacH Geopark has been built around five fundamental and distinct capabilities: Explorer: risk Management: the ability, experience, methodology and creativity to find and the comprehensive management approach to consistently and develop oil and gas reserves in the subsurface – based on the best significantly grow and build economic value per share by effective science, solid economics and ability to take the necessary planning, balanced work programs, cost efficiency focus, secure managed risks. operator: access to capital sources, reliable communication with shareholders, and by accommodating risk among the subsurface, funding, organizational, market, partner/shareholder, and regulatory/political 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, environments. culture: overcome obstacles, seize opportunities and achieve results. the commitment to build a unique performance-driven trust-based consolidator: 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 the ability and initiative to assemble the right balance and portfolio system and represents an integrated approach to align our of upstream assets in the right hydrocarbon basins in the right business objectives with our core principles and responsibilities regions with the right partners and at the right price – coupled with and provides our competitive advantage. the vision and skills to transform and improve value above ground. EXPlORER OPERATOR CONSOlIDATOR RISK mANAGEmENT CUlTURE 16 annual report 2013 annual report 2013 17 ForM 20-F 18 annual report 2013 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, 2013 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: 57,863,615 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. x Yes No Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.* * The registrant became subject to such requirements on February 6, 2014, and it has filed all reports so required since that date. 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 x 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 o 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 GeoPark Limited Table of contents PRESENTATION OF FINANCIAL AND OTHER INFORMATION FORWARD-LOOKING STATEMENTS ENFORCEMENT OF JUDGMENTS 21 24 25 D. Selling shareholders E. Dilution F. Expenses of the issue 26 PART I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS 26 26 A. Directors and senior management ITEM 10. ADDITIONAL INFORMATION A. Share capital B. Memorandum of association and bye-laws 161 161 161 161 161 161 165 165 165 168 168 168 168 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 168 ABOUT MARKET RISK ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 168 168 A. Debt securities B. Warrants and rights C. Other securities D. American Depositary Shares 168 168 168 169 PART II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 169 169 A. Defaults B. Arrears and delinquencies ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS ITEM 15. CONTROLS AND PROCEDURES A. Disclosure Controls and Procedures B. Management’s Annual Report on Internal Control over Financial Reporting C. Attestation Report of the Registered Public Accounting Firm D. Changes in Internal Control over Financial Reporting ITEM 16. [RESERVED] ITEM 16A. Audit committee financial expert ITEM 16B. Code of Conduct ITEM 16C. Principal Accountant Fees and Services ITEM 16D. Exemptions from the listing standards for audit committees ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers ITEM 16F. Change in registrant’s certifying accountant ITEM 16G. Corporate governance ITEM 16H. Mine safety disclosure PART III ITEM 17. Financial statements ITEM 18. Financial statements ITEM 19. Exhibits Glossary of oil and natural gas terms 169 169 169 169 169 169 169 169 169 169 169 170 171 171 171 172 173 173 173 173 176 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 26 26 26 26 26 26 26 34 35 35 61 61 64 125 125 125 126 126 142 147 147 147 147 147 148 148 153 155 156 E. Share ownership 157 ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 157 157 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 20 GeoPark 20F 158 160 160 160 161 161 161 161 161 Presentation of Financial and Other Information Certain definitions Unless otherwise indicated or the context otherwise requires, all references in this annual report to: “Chile” are to the Republic of Chile; “Colombia” are to the Republic of Colombia; “Brazil” are to the Federative Republic of Brazil; “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words “Argentina” are to the Argentine Republic; of a similar effect, are to GeoPark Limited (formerly GeoPark Holdings “Peru” are to the Republic of Peru; Limited), an exempted company incorporated under the laws of Bermuda, “US$” and “U.S. dollars” are to the official currency of the United States together with its consolidated subsidiaries; of America; “Agencia” are to GeoPark Latin America Limited Agencia en Chile, an “Ch$” and “Chilean pesos” are to the official currency of Chile; established branch, under the laws of Chile, of GeoPark Latin America Limited, “Col$” and “Colombian pesos” are to the official currency of Colombia; an exempted company incorporated under the laws of Bermuda; “GBP” are to the official currency of the United Kingdom; “GeoPark Latin America” are to our subsidiary GeoPark Latin America Limited, “AR$” and “Argentine pesos” are to the official currency of Argentina; an exempted company incorporated under the laws of Bermuda; “real,” “reais” and “R$” are to the official currency of Brazil; “GeoPark Fell” are to our subsidiary GeoPark Fell SpA., a sociedad por acciones “IFRS” are to International Financial Reporting Standards as adopted by incorporated under the laws of Chile; the International Accounting Standards Board, or IASB; “GeoPark Chile” are to our subsidiary GeoPark Chile S.A., a sociedad anónima “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels cerrada incorporated under the laws of Chile; Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis ); “GeoPark Colombia” are prior to our internal corporate reorganization of our “CNPE” are to the Brazilian National Council on Energy Policy (Conselho Colombian operations, to our subsidiary GeoPark Colombia S.A., a sociedad Nacional de Política Energética); anónima cerrada incorporated under the laws of Chile and subsequent to “ANH” are to the Colombian National Hydrocarbons Agency (Agencia such reorganization, to GeoPark Colombia Coöperatie U.A., a cooperative duly Nacional de Hidrocarburos); incorporated under the laws of the Netherlands; “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional “GeoPark Colombia S.A.S.” are to our subsidiary GeoPark Colombia S.A.S., a de Petróleo) sociedad anónima simplificada incorporated under the laws of Colombia, “economic interest” means an indirect participation interest in the net which absorbed Winchester, Luna and Cuerva and their Colombian branches revenues from a given block based on bilateral agreements with the by merger and assumed all rights and obligations of each; concessionaires; and “Winchester” are to our subsidiary Winchester Oil and Gas S.A., now GeoPark “working interest” means the right granted to the lessee of a property to Colombia PN S.A. Sucursal Colombia, a Colombian branch of a sociedad explore for and to produce and own oil, gas, or other minerals. The working anónima incorporated under the laws of Panama, which merged into GeoPark interest owners bear the exploration, development and operating costs on Colombia S.A.S.; either a cash, penalty or carried basis. “Luna” are to our subsidiary La Luna Oil Company Limited S.A., a sociedad anónima incorporated under the laws of Panama, which merged into GeoPark Colombia S.A.S.; “Cuerva” are to our subsidiary GeoPark Cuerva LLC, formerly known as Hupecol Caracara LLC, a limited liability company incorporated under the laws of the state of Delaware, which merged into GeoPark Colombia S.A.S.; “LGI” are to LG International Corp., a company incorporated under the laws of Korea; “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; “Rio das Contas” are to Rio das Contas Produtora de Petróleo Ltda., a limited liability company incorporated under the laws of Brazil; our “Brazil Acquisitions” are to our Rio das Contas acquisition, which we completed on March 31, 2014, our award of two new concessions by the ANP, which are subject to confirmation of qualification requirements, and our award of seven new concessions by the ANP, in Brazil; GeoPark 20F 21 Financial statements Financial statements Our consolidated financial statements This annual report includes our audited consolidated financial statements • The combined statement of financial position for GeoPark as of December 31, 2013 to give pro forma effect to the acquisition of Rio das Contas as if such acquisition had occurred as of December 31, 2013. as of December 31, 2013 and 2012 and for each of the years ended December We refer to these pro forma financial statements as our Unaudited Condensed 31, 2013, 2012 and 2011, or our Annual Consolidated Financial Statements. Combined Pro Forma Financial Data. For purposes of preparing our Our Consolidated Financial Statements are presented in U.S. dollars and have certain adjustments to the historical and pre-acquisition financial information been prepared in accordance with IFRS, as issued by the International of Rio das Contas. See “Item 3. Key Information—A. Selected financial data— Accounting Standards Board (“IASB”). Unaudited Condensed Combined Pro Forma Financial Data.” Our Unaudited Unaudited Condensed Combined Pro Forma Financial Data, we have made Our Annual Consolidated Financial Statements have been audited by Price informational purposes only and does not purport to represent our results of Waterhouse & Co. S.R.L., Argentina, a member firm of PricewaterhouseCoopers operations or financial condition had our acquisition of Rio das Contas Network, or PwC, an independent registered public accounting firm, as stated occurred at the respective dates indicated above. Condensed Combined Pro Forma Financial Data is presented for in their report included elsewhere in this annual report. Our fiscal year ends December 31. References in this annual report to a fiscal read in conjunction with “Item 5. Operating and Financial Review and year, such as “fiscal year 2013,” relate to our fiscal year ended on December Prospects,” our Consolidated Financial Statements and the Rio das Contas Our historical financial information and pro forma financial data should be 31 of that calendar year. Consolidated Financial Statements, including, in each case, the accompanying notes thereto, included elsewhere in this annual report. Acquisition of Rio das Contas On May 14, 2013, we agreed to acquire all of the issued and outstanding shares of Rio das Contas from Panoro, for a total cash consideration of US$140 million subject to certain purchase price and easement adjustments. Non IFRS financial measures Adjusted EBITDA Adjusted EBITDA is a supplemental non-IFRS financial measure that is used The closing of the acquisition was subject to certain conditions, including by management and external users of our financial statements, such as approval by the ANP, among others. We closed the acquisition on March industry analysts, investors, lenders and rating agencies. 31, 2014. References to Rio das Contas Consolidated Financial Statements are to the Rio income tax, depreciation, amortization and certain non-cash items such as das Contas Audited Consolidated Financial Statements. Our results as impairments and write-offs of unsuccessful exploration and evaluation assets, reflected in our Consolidated Financial Statements included in this annual accrual of stock options and stock awards and bargain purchase gain on report are not comparable to our results for any period following the future date on which we consolidate the results of Rio das Contas. acquisition of subsidiaries. Adjusted EBITDA is not a measure of profit or cash flows as determined by IFRS. We define Adjusted EBITDA as profit for the period before net finance cost, Pro forma financial data In light of our Rio das Contas acquisition that closed on March 31, 2014, We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our we include in this annual report Unaudited Condensed Combined Pro Forma operations from period to period without regard to our financing methods Financial Data to illustrate: or capital structure. We exclude the items listed above from profit for the period in arriving at Adjusted EBITDA because these amounts can vary • The combined results of operations for GeoPark for the year ended substantially from company to company within our industry depending upon December 31, 2013 to give pro forma effect to the acquisition of Rio das accounting methods and book values of assets, capital structures and the Contas as if such transaction had occurred as of January 1, 2013; and method by which the assets were acquired. Adjusted EBITDA should not be 22 GeoPark 20F 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 Market share and other information Market data, other statistical information, information regarding recent or as an indicator of our operating performance or liquidity. Certain items developments in Chile, Colombia, Brazil and Argentina and certain industry excluded from Adjusted EBITDA are significant components in understanding forecast data used in this annual report were obtained from internal reports and assessing a company’s financial performance, such as a company’s cost and studies, where appropriate, as well as estimates, market research, of capital and tax structure and significant and/or recurring write-offs, as publicly available information (including information available from the SEC well as the historic costs of depreciable assets, none of which are components website) and industry publications. Industry publications generally state that of Adjusted EBITDA. Our computation of Adjusted EBITDA may not be the information they include has been obtained from sources believed to comparable to other similarly titled measures of other companies. be reliable, but that the accuracy and completeness of such information is not guaranteed. Similarly, internal reports and studies, estimates and market For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit research, which we believe to be reliable and accurately extracted by us for the year, see Note 6 to our Annual Consolidated Financial Statements for use in this annual report, have not been independently verified. However, as of and for the years ended 2012 and 2013, included in this annual report. 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 We have also included Pro Forma Adjusted EBITDA in this annual report to reproduction in this annual report. show our Adjusted EBITDA after giving pro forma effect to our Rio das Contas acquisition that closed on March 31, 2014. For a reconciliation of Pro Forma In addition, we have provided definitions for certain industry terms used Adjusted EBITDA to the IFRS financial measure of pro forma profit for the year, in this annual report in the “Glossary of oil and natural gas terms” included as see “Item 3. Key Information—A. Selected financial data—Unaudited Appendix A to this annual report. Condensed Combined Pro Forma Financial Data—Note 2—Reconciliations.” 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 Reserves Report The information included in this annual report regarding estimated quantities of proved reserves in Brazil, Chile, Colombia and Argentina is derived, in part, from estimates of the proved reserves as of December 31, 2013. 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, 2013 of oil and gas reserves located in the Fell Block in Chile, the Del Mosquito, Cerro Doña Juana and Loma Cortaderal Blocks in Argentina and the La Cuerva, Llanos 32, Llanos 34, Llanos 17 and Yamú Blocks in Colombia and the interests held through Rio das Contas, which we acquired on March 31, 2014, in Brazil in BCAM-40 Concession (Manatí). Information about our reserves only presents reserves estimates for our working interests in the blocks covered by such report as of the date of such report. These estimates are included in this annual report in reliance upon the authority of D&M as an expert in these matters. GeoPark 20F 23 Forward-looking Statements This annual report contains statements that constitute forward-looking • market or business conditions and fluctuations in global and local demand statements. Many of the forward-looking statements contained in this annual for energy; report can be identified by the use of forward-looking words such as • the direct or indirect impact on our business resulting from terrorist “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” incidents or responses to such incidents, including the effect on the “estimate” and “potential,” among others. availability of and premiums on insurance; and • other factors discussed under “Item 3. Key Information—D. Risk factors” in Forward-looking statements appear in a number of places in this annual this annual report. report and include, but are not limited to, statements regarding our intent, belief or current expectations. Forward-looking statements are based on Forward-looking statements speak only as of the date they are made, and our management’s beliefs and assumptions and on information currently we do not undertake any obligation to update them in light of new available to our management. Such statements are subject to risks and information or future developments or to release publicly any revisions to uncertainties, and actual results may differ materially from those expressed these statements in order to reflect later events or circumstances or to or implied in the forward-looking statements due to various factors, reflect the occurrence of unanticipated events. including, but not limited to, those identified under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties include factors relating to: • operating risks, including equipment failures and the amounts and timing of revenues and expenses; • termination of, or intervention in, concessions, rights or authorizations granted by the Chilean, Colombian, Brazilian and Argentine governments to us; • uncertainties inherent in making estimates of our oil and natural gas data; • 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; • availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services; • contract counterparty risk; • projected and targeted capital expenditures and other cost commitments and revenues; • weather and other natural phenomena; • the impact of recent and future regulatory proceedings and changes, changes in environmental, health and safety and other laws and regulations to which our company or operations are subject, as well as changes in the application of existing laws and regulations; • current and future litigation; • our ability to successfully identify, integrate and complete acquisitions • our ability to retain key members of our senior management and key technical employees; • competition from other similar oil and natural gas companies; 24 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 its Colombia, Brazil and Argentina. In addition, most of our directors and directors, officers and auditors against any liability incurred by them in executive officers reside outside the United States, and all or a substantial defending any proceedings, whether civil or criminal, in which judgment portion of the assets of such persons are located outside the United States. is awarded in their favor or in which they are acquitted or granted relief by As a result, it may be difficult for investors to effect service of process on the Supreme Court of Bermuda pursuant to Section 281 of the Bermuda those persons in the United States or to enforce in the United States Companies Act. 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 action for the reciprocal recognition and enforcement of judgments in civil and by such director or officer, except in respect of any fraud or dishonesty of commercial matters. As a result, whether a U.S. judgment would be such director or officer. We may also indemnify our directors and officers in enforceable in Bermuda against us or our directors and officers depends on their capacity as directors and officers for any loss arising or liability attaching whether the U.S. court that entered the judgment is recognized by the to them by virtue of any rule of law in respect of any negligence, default, Bermuda court as having jurisdiction over us or our directors and officers, breach of trust of which a director or officer may be guilty in relation to the as determined by reference to Bermuda conflict of law rules and the company other than in respect of his own fraud or dishonesty. We have judgment is not contrary to public policy in Bermuda, has not been obtained 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 for No treaty exists between the United States and Chile for the reciprocal 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 of have enforced valid and conclusive judgments for the payment of money 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 public An action brought pursuant to a public or penal law, the purpose of which policy have been respected, without retrial or review of the merits of the is the enforcement of a sanction, power or right at the instance of the state in subject matter. If a U.S. court grants a final judgment, enforceability of this its sovereign capacity, may not be entertained by a Bermuda court. Certain judgment in Chile will be subject to obtaining the relevant exequatur (i.e., remedies available under the laws of U.S. jurisdictions, including certain recognition and enforcement of the foreign judgment) according to Chilean remedies under U.S. federal securities laws, may not be available under civil procedure law in effect at that time, and depending on certain factors Bermuda law or enforceable in a Bermuda court, as they may be contrary to (the satisfaction or non-satisfaction of which would be determined by the 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. 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 reciprocity in federal securities laws because these laws have no extraterritorial jurisdiction the recognition and enforcement of the foreign judgment between the under Bermuda law and do not have force of law in Bermuda. A Bermuda United States and Chile, that judgment would not be enforced in Chile); the court may, however, impose civil liability on us or our directors and officers absence of any conflict between the foreign judgment and Chilean laws if the facts alleged in a complaint constitute or give rise to a cause of action (excluding for this purpose the laws of civil procedure) and Chilean public under Bermuda law. However, section 281 of the Bermuda Companies policy; the absence of a conflicting judgment by a Chilean court relating to Act allows a Bermuda court, in certain circumstances, to relieve officers and the same parties and arising from the same facts and circumstances; the directors of Bermuda companies of liability for acts of negligence, breach Chilean court’s determination that the U.S. courts had jurisdiction, that of duty or trust or other defaults. process was appropriately served on the defendant and that the defendant was afforded a real opportunity to appear before the court and defend its Section 98 of the Bermuda Companies Act provides generally that a Bermuda case; and the judgment being final under the laws of the country in which it company may indemnify its directors, officers and auditors against any was rendered. Nonetheless, we have been advised by our Chilean counsel liability which by virtue of any rule of law would otherwise be imposed on that there is doubt as to the enforceability in original actions in Chilean courts them in respect of any negligence, default, breach of duty or breach of trust, of liabilities predicated solely upon U.S. federal or state securities laws. except in cases where such liability arises from fraud or dishonesty of which GeoPark 20F 25 Part I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS We have not included selected consolidated financial data as of and for the years ended December 31, 2009 and 2010 in the tables below. We have not presented financial data prior to this period 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. As a result we have not prepared financial information in IFRS prior to December 31, 2011. 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, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 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, 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 prior to their incorporation into our financial statements, or our Brazil Acquisitions. 26 GeoPark 20F Statement of Income Data For the year ended December 31, 2013 2012 2011 (in thousands of US$, except per share numbers) Revenue Net oil sales Net gas sales Net revenue Production costs Gross profit(1) Exploration costs Administrative costs Selling expenses Other operating income/(expense) Operating profit Financial income Financial expenses 315,435 22,918 338,353 (179,643) 158,710 (16,254) 46,584) (17,252) 5,344 83,964 4,893 (38,769) 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 50,088 (15,154) 34,934 12,922 22,012 0.50 0.47 221,564 28,914 250,478 (129,235) 121,243 (27,890) (28,798) (24,631) 823 40,747 892 (17,200) 8,401 32,840 (14,394) 18,446 6,567 11,879 0.28 0.27 73,508 38,072 111,580 (54,513) 57,067 (10,066) (18,232) (2,546) (439) 25,784 162 (13,678) — 12,268 (7,206) 5,062 5,008 54 0.00 0.00 outstanding - Basic 43,603,846 42,673,981 41,912,685 Weighted average common shares outstanding - Diluted(2) 46,532,049 44,109,305 43,917,167 (1) Gross profit is defined as net revenue minus production costs. (2) See Note 18 to our Annual Consolidated Financial Statements. GeoPark 20F 27 Balance Sheet Data As of December 31, (in thousands of US$) Assets Non-current assets Property, plant and equipment Prepaid taxes Other financial assets Deferred income tax Prepayments and other receivables Total non-current assets Current assets Other financial assets Inventories Trade receivables Prepayments and other receivables Prepaid taxes Cash at bank and in hand Total current assets Total assets Share capital Share premium Other Equity attributable to owners of the Company Equity attributable to non-controlling interest Total equity Liabilities Non-current liabilities Borrowings Provisions for other long-term liabilities Trade and other payables Deferred income tax Total non-current liabilities Current liabilities Borrowings Current income tax Trade and other payables Total current liabilities Total liabilities 2013 2012 2011 595,446 11,454 5,168 13,358 6,361 631,787 — 8,122 42,628 35,764 6,979 121,135 214,628 846,415 44 120,426 150,371 270,841 95,116 365,957 290,457 33,076 8,344 23,087 354,964 26,630 7,231 91,633 125,494 480,458 457,837 10,707 7,791 13,591 510 490,436 — 3,955 32,271 49,620 3,443 48,292 137,581 628,017 43 116,817 122,561 239,421 72,665 312,086 165,046 25,991 — 17,502 208,539 27,986 7,315 72,091 107,392 315,931 224,635 2,957 5,226 450 707 233,975 3,000 584 15,929 24,984 147 193,650 238,294 472,269 43 112,231 96,615 208,889 41,763 250,652 134,643 9,412 — 13,109 157,164 30,613 187 33,653 64,453 221,617 Total equity and liabilities 846,415 628,017 472,269 28 GeoPark 20F Cash Flow Data For the year ended December 31, 2013 2012 2011 (in thousands of US$) Cash provided by (used in) Operating activities Investing activities Financing activities Net increase (decrease) in cash Other Financial Data 140,094 (221,299) 164,018 82,813 131,802 (303,507) 26,375 (145,330) For the year ended December 31, 2013 2012 Adjusted EBITDA(1) (US$ thousands) Adjusted EBITDA margin(2) Adjusted EBITDA per boe(3) 167,253 49.4% 33.9 121,404 48.5% 31.1 68,763 (101,276) 131,739 99,226 2011 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 as of and for the years ended 2012 and 2013, 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 production expressed in boe. GeoPark 20F 29 Unaudited Condensed Combined Pro Forma Financial Data The following Unaudited condensed combined pro forma income statement Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by data below is presented as if the acquisitions of Rio das Contas had occurred management and external users of our financial statements, such as industry as of January 1, 2013. The Unaudited condensed combined pro forma analysts, investors, lenders and rating agencies. We define Adjusted EBITDA statement of financial position is presented below as if our Rio das Contas as profit for the period before net finance cost, income tax, depreciation, acquisition had occurred on December 31, 2013. amortization and certain non-cash items such as impairments and write-off The Unaudited Condensed Combined Pro Forma Financial Data is based on awards and bargain purchase gain on acquisition of subsidiaries. the following financial statements included elsewhere in this annual report and should be read in conjunction with them and the notes thereto: Adjusted EBITDA is not a measure of profit or cash flows as determined • our Annual Audited Consolidated Financial Statements; and by IFRS and may not be comparable to other similarly-titled measures of • the Rio das Contas Audited Consolidated Financial Statements; other companies. of exploration and evaluation assets, accrual of stock options and stock Rio das Contas was acquired on March 31, 2014. The Rio das Contas pre- acquisition income statement data for the year ended December 31, 2013 and the pre-acquisition statement of financial position data as of December 31, 2013 have been extracted from the Rio das Contas Audited Consolidated Financial Statements. The preparation of the Unaudited Condensed Combined Pro Forma Financial Data includes the impact of certain purchase accounting adjustments, such as estimated changes in depreciation expense on acquired proved and unproved properties that are expected to have a continuing impact on us. Accordingly, the amounts shown in our Unaudited Condensed Combined Pro Forma Financial data are not necessarily indicative of the results that would have resulted if the acquisitions had occurred on January 1, 2013 or that may result in the future. The Unaudited Condensed Combined Pro Forma Financial Data is for informational purposes only. Because of its nature, it addresses a hypothetical situation and it is not intended to represent or to be indicative of the consolidated financial position or results of operations that we would have reported had the acquisitions been completed on the dates indicated. It should not be relied upon as representative of the historical consolidated financial position or results of operations that would have been achieved, or the future consolidated financial position or operating results that can be expected. The unaudited pro forma adjustments, described in the accompanying notes, are based on available information and certain assumptions that management believes are reasonable for purposes of this annual report. 30 GeoPark 20F Unaudited Condensed Combined Pro Forma Income Statement (in thousands of US$) GeoPark Rio das Contas adjustments Pro Forma For the year ended December 31, 2013 IFRS IFRS historical historical Net revenue Production costs Gross profit Exploration costs Administrative costs Selling expenses Other operating income Operating profit/(loss) Net financial result Profit/(loss) before income tax Income tax Profit/(loss) for the year Attributable to: Owners of the Company Non-controlling interest Earnings per share (in US$) for profit attributable to owners of the Company: Basic Diluted Weighted average number of shares: Basic Diluted Rio das Contas acquisition(1) Pro Forma combined — (a)(12,403) (12,403) 386,923 (214,907) 172,016 338,353 (179,643) 158,710 (16,254) (46,584) (17,252) 5,344 83,964 (33,876) 50,088 (15,154) 34,934 48,570 (22,861) 25,709 — (2,021) — — — — — — 23,688 (12,403) 353 24,041 (4,659) 19,382 (b)(2,934) (15,337) (c)5,214 (10,122) (16,254) (48,605) (17,252) 5,344 95,249 (36,457) 58,792 (14,599) 44,194 22,012 12,922 19,382 — (10,122) — 31,272 12,922 0.50 0.47 43,603,846 46,532,049 0.72 0.67 43,603,846 46,532,049 (1) See Notes to the Unaudited Condensed Combined Pro Forma Financial Data below. GeoPark 20F 31 Unaudited Condensed Combined Pro Forma Statement of Financial Position (in thousands of US$) For the year ended December 31, 2013 historical IFRS historical IFRS GeoPark Rio das Contas Pro Forma adjustments Rio das Contas acquisition(1) Pro Forma combined Assets Property, plant and equipment Other Total non-current assets Trade receivables Prepayments and other receivables Cash at bank and in hand Other Total current assets Total assets Equity Share premium Reserves Other Attributable to owners of the Company Non-controlling interest Total equity Liabilities Borrowings Provisions for other long-term liabilities Deferred income tax Trade and other payables Contingent payment Total non-current liabilities Trade and other payables Borrowings Other Total current liabilities Total liabilities Total equity and liabilities 595,446 36,341 631,787 42,628 35,764 121,135 15,101 214,628 846,415 120,426 126,465 23,950 270,841 95,116 365,957 290,457 33,076 23,087 8,344 — 354,964 91,633 26,630 7,231 125,494 480,458 846,415 64,754 394 65,148 9,546 142 17,015 117 26,820 91,968 64,865 5,783 6,784 77,432 — (d)71,512 — 71,512 — — (e)(77,894) — (77,894) (6,382) (f)(64,865) (f)(5,783) (f)(6,784) (77,432) — 77,432 (77,432) 731,712 36,735 768,447 52,174 35,906 60,256 15,218 163,554 932,001 120,426 126,465 23,950 270,841 95,116 365,957 — 6,671 3,247 — — 9,918 634 — 3,984 4,618 14,536 91,968 (g)70,450 360,907 — — — (h)600 39,747 26,334 8,344 600 71,050 435,932 — — — — 71,050 (6,382) 92,267 26,630 11,215 130,112 566,044 932,001 (1) See Notes to the Unaudited Condensed Combined Pro Forma Financial Data below. 32 GeoPark 20F Notes to the Unaudited Condensed Combined Pro Forma Financial Data Note 1 will bear a variable interest rate equal six-month LIBOR + 3.9%. The effect Purchase price adjustments on Rio das Contas acquisition of a 1⁄8 percent variance in the interest rate on profit for the year would be US$0.3 million for the year ended December 31, 2013. The purchase price allocation of our Rio das Contas acquisition is preliminary (c) Decrease in income taxes related to foregoing adjustments. The rate and may be subject to change. The final purchase price may result in applied for adjustments (a) and (c) is the statutory rate in Brazil of 34%. an adjustment to the purchase price or its allocation. Any such adjustment will be reflected as an increase or decrease by means of working capital The following pro forma adjustments were made to the unaudited condensed adjustment to be determined when certain information is available. combined pro forma statement of financial position to reflect the acquisition (in thousands of US$) Cost of the acquisition Cash payment(i) Total cost of the acquisition Less: Book value of assets acquired and liabilities assumed Total book value of assets acquired and liabilities assumed Fair value adjustments: Proved and unproved properties(ii) Fair value of assets acquired and liabilities assumed of Rio das Contas as if it had occurred on December 31, 2013: (d) Fair value adjustment of US$71.5 million allocated to the recognition of mineral interest. 140,100 (e) Adjustment to reflect: (i) increase in cash of US$70.5 million due to bank 140,100 indebtedness issued in connection with the acquisition; and (ii) cash payment 77,432 62,668 of US$140.1 million relating to the acquisition. (f) Elimination of Rio das Contas equity items for consolidation purposes. (g) Bank indebtedness of US$70.5 million incurred in connection with the acquisition. (h) Contingent payment of US$0.6 million relating to the acquisition. The purchase price is adjusted for an earn-out amount equal to 45% of the net 140,100 cash flows of the BCAM-40 Concession in excess of US$25 million. The earn- out amount is calculated over a five-year period starting January 1, 2013. (i) Comprised of a fixed purchase price of US$140 million, increased by a working capital adjustment of US$0.1 million calculated based on the Rio das Contas Consolidated Financial Statements. The working capital Note 2 adjustment is preliminary and is subject to final agreement with the seller. Reconciliations (ii) Reflects fair value adjustments of property, plant and equipment and the recognition of mineral interest. Reconciliation of pro forma Adjusted EBITDA to the IFRS financial measure of pro forma profit for the year The following pro forma adjustments were made to the unaudited condensed combined pro forma income statement for the year ended December 31, 2013 to reflect the acquisition of Rio das Contas as if it had occurred on (in thousands of US$) January 1, 2013: (a) Additional depreciation expense resulting from the increased basis of property, plant and equipment acquired of US$9.5 million for the year ended Pro Forma profit for the year attributable to owners of the Company Pro Forma non-controlling interest December 31, 2013. Also, the accounting policy for depreciation of oil Pro Forma profit for the year and gas properties was adjusted to conform to our policy (which is based Pro Forma income tax on commercial proved and probable reserves) resulting in additional depreciation expense of US$2.9 million for the year ended December 31, 2013. Pro Forma net finance results Pro Forma others(i) Pro Forma impairment and write off of unsuccessful efforts (b) Interest expense on US$70.5 million credit facility incurred in connection Pro Forma accrual of stock options and stock awards with the acquisition is calculated using an effective interest rate of 4.2% for Pro Forma depreciation the year ended December 31, 2013. The loan, which is secured by the benefits Pro Forma Adjusted EBITDA GeoPark receives under the Purchase and Sale Agreement for Natural Gas with Petrobras, will mature five years from the date of disbursement and (i) Includes capitalized costs for the year ended December 31, 2013. For the year ended December 31, 2013 31,272 12,922 44,194 14,599 36,457 (7,040) 10,962 9,167 89,724 198,062 GeoPark 20F 33 Reconciliation of Rio das Contas historical Adjusted EBITDA to the IFRS exchange rate for the purchase of U.S. dollars as reported by the Central Bank measure of Rio das Contas historical profit for the year of Brazil was R$2.2257 per U.S. dollar. (in thousands of US$) December 31, 2013 rate during the months indicated. For the year ended The following table presents the monthly high and low representative market Recent exchange rates of real per U.S. dollar Low High Rio das Contas historical profit for the year Income tax Net financial result Depreciation 19,382 4,659 (353) 7,121 Month: October 2013 Rio das Contas historical Adjusted EBITDA 30,809 November 2013 Exchange rates In Chile, Colombia and Argentina, our functional currency is the U.S. dollar. In Brazil, our functional currency is the real . December 2013 January 2014 February 2014 March 2014 April 2014 (through April 25, 2014) The Brazilian foreign exchange system allows the purchase and sale of foreign currency and the international transfer of real by any person or legal entity, Source: Central Bank of Brazil. regardless of the amount, subject to certain regulatory procedures. 2.1611 2.2426 2.3102 2.3335 2.3334 2.2603 2.1974 2.2123 2.3362 2.3817 2.4397 2.4238 2.3649 2.2811 Since 1999, the Brazilian Central Bank has allowed the U.S. dollar-real market rate for each of the five most recent years, calculated by using exchange rate to float freely, and, since then, the U.S. dollar- real exchange the average of the exchange rates on the last day of each month during the rate has fluctuated considerably. period, and the representative year-end market rate for each of the five The following table presents the average R$ per U.S. dollar representative Our operations in Brazil account for 12% of our consolidated assets and 21% most recent years. of our production each on a pro forma basis, after giving effect to our Rio Real per U.S. dollar Average Period-end das Contas acquisition, which closed on March 31, 2014. This portion of our Period: business is exposed to losses that may arise from currency fluctuation. In the past, the Brazilian Central Bank has occasionally intervened to control unstable movements in foreign exchange rates. We cannot predict whether the Brazilian Central Bank or the Brazilian government will continue to permit 2009 2010 2011 2012 the real to float freely or will intervene in the exchange rate market through First quarter 2013 the return of a currency band system or otherwise. The real may depreciate or appreciate substantially against the U.S. dollar. Furthermore, Brazilian law Second quarter 2013 Third quarter 2013 provides that, whenever there is a serious imbalance in Brazil’s balance of Fourth quarter 2013 payments or there are serious reasons to foresee a serious imbalance, First quarter 2014 temporary restrictions may be imposed on remittances of foreign capital Second quarter 2014 (through April 25, 2014) abroad. We cannot assure you that such measures will not be taken by the Brazilian government in the future. See “—D. Risk factors—Risks relating Source: Central Bank of Brazil. to our business—Our results of operations could be materially adversely 1.9936 1.7593 1.6746 1.9550 1.9964 2.0700 2.2889 2.2735 2.3409 2.2331 1.7412 1.6662 1.8758 2.0435 2.0138 2.2156 2.2300 2.3426 2.2630 2.2325 affected by fluctuations in foreign currency exchange rates.” Exchange rate fluctuation may affect the U.S. dollar value of any distributions The following tables show the selling rate for U.S. dollars for the periods Risks relating to our business—Our results of operations could be materially and dates indicated. The information in the “Average” column represents the adversely affected by fluctuations in foreign currency exchange rates.” we make with respect to our common shares. See “—D. Risk factors— average of the daily exchange rates during the periods presented. The numbers in the “Period-end” column are the quotes for the exchange rate as of the last business day of the period in question. As of April 15, 2014, the B. Capitalization and indebtedness Not applicable. 34 GeoPark 20F C. Reasons for the offer and use of proceeds Not applicable. • proximity and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of competitors’ supplies of oil and natural gas in D. Risk factors Our business, financial condition and results of operations could be materially captive market areas; • quality discounts for oil production based, among other things, on API and adversely affected if any of the risks described below occur. As a result, and mercury content; the market price of our common shares could decline, and you could lose all • taxes and royalties under relevant laws and the terms of our contracts; or part of your investment. This annual report also contains forward-looking • our ability to enter into oil and natural gas sales contracts at fixed prices; statements that involve risks and uncertainties. See “Forward-Looking • the level of global methanol demand and inventories and changes in Statements.” The risks below are not the only ones facing our Company. the uses of methanol; Additional risks not currently known to us or that we currently deem • the price and availability of alternative fuels; and immaterial may also adversely affect us. • future changes to our hedging policies. Risks relating to our business These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements. For example, A substantial or extended decline in oil, natural gas and methanol prices from January 1, 2010 to December 31, 2013, NYMEX West Texas International, may materially adversely affect our business, financial condition or results or WTI, crude oil contracts prices ranged from a low of US$64.78 per bbl of operations. to a high of US$113.39 per bbl, Henry Hub natural gas average monthly spot prices ranged from a low of US$1.82 per mmbtu to a high of US$7.51 per The prices that we receive for our oil and natural gas production heavily mmbtu, US Gulf methanol spot barge prices ranged from a low of US$324.61 influence our revenues, profitability, access to capital and growth rate. per metric ton to a high of US$530.71 per metric ton and Brent spot prices Historically, the markets for oil, natural gas and methanol (which historically ranged from a low of US$67.18 per barrel to a high of US$128.14 per barrel. have influenced prices for almost all of our Chilean gas sales) have been Further, oil, natural gas and methanol prices do not necessarily fluctuate volatile and will likely continue to be volatile in the future. International oil, in direct relationship to each other. natural gas and methanol prices have fluctuated widely in recent years and may continue to do so in the future. As of December 31, 2013, natural gas comprised 26% of our net proved reserves. On a pro forma basis, after giving effect to our Rio das Contas The prices that we will receive for our production and the levels of our acquisition, which closed on March 31, 2014 natural gas comprised 47% of production depend on numerous factors beyond our control. These factors our net proved reserves. A decline in natural gas prices could negatively include, but are not limited, to the following: affect our future growth, particularly for future gas sales where we may not • global economic conditions; be able to secure or extend our current long-term contracts. • changes in global supply and demand for oil, natural gas and methanol; • the actions of the Organization of the Petroleum Exporting Countries, or OPEC; For the year ended December 31, 2013, 93% of our revenues, were derived from oil. Giving effect on a pro forma basis to our Rio das Contas acquisition, • political and economic conditions, including embargoes, in oil-producing which closed on March 31, 2014, 81.5% of our revenues would have countries or affecting other countries; been derived from oil in the same period. See “Item 3. Key Information—A. • the level of oil- and natural gas-producing activities, particularly in the Selected financial data—Unaudited Condensed Combined Pro Forma Middle East, Africa, Russia, South America and the United States; Financial Data.” Because we expect that our production mix will continue • the level of global oil and natural gas exploration and production activity; to be weighted toward oil, our financial results are more sensitive to • the level of global oil and natural gas inventories; movements in oil prices. • the price of methanol; • availability of markets for natural gas; Lower oil and natural gas prices may not only decrease our revenues on a • weather conditions and other natural disasters; per unit basis, but also may reduce the amount of oil and natural gas that we • technological advances affecting energy production or consumption; can produce economically. In addition, changes in oil and gas prices can • domestic and foreign governmental laws and regulations, including impact our valuation of reserves and, in periods of sharply lower commodity environmental, health and safety laws and regulations; prices, we may curtail production and capital spending projects or may defer GeoPark 20F 35 or delay drilling wells because of lower cash flows. A substantial or extended gas to enable us to continue to operate profitably. If we are unable to replace decline in oil or natural gas prices would materially adversely affect our our current and future production, the value of our reserves will decrease, and business, financial condition and results of operations. We have historically our business, financial condition and results of operations will be materially not hedged our production to protect against fluctuations in the international adversely affected. oil prices. We may in the future consider adopting a hedging policy against commodity price risk, when deemed appropriate and taking into account the We derive a significant portion of our revenues from sales to a few key size of our business and market volatility. customers. Unless we replace our oil and natural gas reserves, our reserves and In Chile, 100% of our crude oil and condensate sales are made to ENAP. production will decline over time. Our business is dependent on our For the year ended December 31, 2013, sales to ENAP represented 42.6% of continued successful identification of productive fields and prospects and our revenues from oil and 39.8% of our total revenues. ENAP imports the the identified locations in which we drill in the future may not yield oil or majority of the oil it refines and partially supplements those imports with natural gas in commercial quantities. volumes supplied locally by its own operated fields and those operated by us. The sales contract with ENAP is commonly revised every two years to reflect Production from oil and gas properties declines as reserves are depleted, changes in the global oil market and to adjust for ENAP’s logistics costs with the rate of decline depending on reservoir characteristics. Accordingly, in the Gregorio oil terminal. The current agreement was recently executed our current proved reserves will decline as these reserves are produced. and signed, with an initial term of 1 year, until March 2015, and it will be For instance, based on our internal projections, we estimate that the daily automatically extended for periods of 1 year until the expiration of the Fell production in our Colombian blocks will peak in 2015 and decline thereafter, Block CEOP, which is the earlier of August 24, 2032 or the date on which we and that the daily production in the Fell Block and the Tierra del Fuego cease exploitation of hydrocarbons in the Fell Block. However, if ENAP were to Blocks will peak in 2016 and decline thereafter. As of December 31, 2013, decrease or cease purchasing oil from us, or if we were unable to renew our our reserves-to-production (or reserve life) ratio for net proved reserves contract with ENAP at a lower sales price or at all, this could have a material in Chile and Colombia was 3.5 years. According to estimates, if on January 1, adverse effect on our business, financial condition and results of operations. 2014, we ceased all drilling and development and workovers, including recompletions, refracs and workovers, our proved developed producing In Colombia, for the year ended December 31, 2013, we made 52.5% of our reserves base in Chile, Colombia and Argentina would decline at an annual oil sales to Gunvor, 20.9% to Hocol S.A., or Hocol, a subsidiary of Ecopetrol, effective rate of 50% over the first three years, including 50% during the and 9.8% to Perenco, with Gunvor accounting for 27.8%, Hocol 11.1% and first year. In Brazil, we estimate that daily production in the Manatí Field, in Perenco 5.2% of our overall revenues for the same period. Our current sales which we acquired an interest as a result of the Rio das Contas acquisition contracts with Hocol, Perenco and Gunvor are short-term agreements. If on March 31, 2014, will peak in 2017 and decline thereafter. We estimate any of Hocol, Perenco or Gunvor were to decrease or cease purchasing oil that, if on January 1, 2014, all drilling and development and workovers had from us, or if any of them were to decide not to renew their contracts with us ceased, including recompletions, refracs and workovers, then the proved developed producing reserves base attributable to the Manatí Field in Brazil or to renew them at a lower sales price, this could have a material adverse effect on our business, financial condition and results of operations. would have no decline in the first year, but would decline at an annual effective rate of approximately 30% per year over the next three years. In Brazil, following our Rio das Contas acquisition, which closed on March 31, Our future oil and natural gas reserves and production, and therefore our Field in Brazil will be generated from sales to Petrobras, the operator of cash flows and income, are highly dependent on our success in efficiently the Manatí Field, pursuant to a long-term gas off-take contract. See “Item 4. developing our current reserves and using cost-effective methods to find or Information on the Company—B. Business overview—Significant acquire additional recoverable reserves. While we have had success in agreements—Brazil—Petrobras Natural Gas Purchase Agreement.” identifying and developing commercially exploitable deposits and drilling locations in the past, we may be unable to replicate that success in the There are inherent risks and uncertainties relating to the exploration and 2014, we expect that all of our revenues from the sale of gas in the Manatí future. We may not identify any more commercially exploitable deposits or production of oil and natural gas. successfully drill, complete or produce more oil or gas reserves, and the wells which we have drilled and currently plan to drill within our blocks or Our performance depends on the success of our exploration and production concession areas may not discover or produce any further oil or gas or may activities and on the existence of the infrastructure that will allow us to take not discover or produce additional commercially viable quantities of oil or advantage of our oil and gas reserves. Oil and natural gas exploration and 36 GeoPark 20F production activities are subject to numerous risks beyond our control, awarded to us by the ANP to allow us to identify any potential drilling including the risk that exploration activities will not identify commercially locations. viable quantities of oil or natural gas. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on Our ability to drill and develop these identified potential drilling locations the evaluation of seismic and other data obtained through geophysical, depends on a number of factors, including oil and natural gas prices, the geochemical and geological analysis, production data and engineering availability and cost of capital, drilling and production costs, the availability studies, the results of which are often inconclusive or subject to varying of drilling services and equipment, drilling results, lease expirations, the interpretations. availability of gathering systems, marketing and transportation constraints, refining capacity, regulatory approvals and other factors. Because of the Furthermore, the marketability of any oil and natural gas production from uncertainty inherent in these factors, there can be no assurance that our projects may be affected by numerous factors beyond our control. These the numerous potential drilling locations we have identified will ever be factors include, but are not limited to, proximity and capacity of pipelines and drilled or, if they are, that we will be able to produce oil or natural gas from other means of transportation, the availability of upgrading and processing these or any other potential drilling locations. facilities, equipment availability and government laws and regulations (including, without limitation, laws and regulations relating to prices, sale Our business requires significant capital investment and maintenance restrictions, taxes, governmental stake, allowable production, importing and expenses, which we may be unable to finance on satisfactory terms or at all. exporting of oil and natural gas, environmental protection and health and safety). The effect of these factors, individually or jointly, cannot be accurately The oil and natural gas industry is capital intensive and we expect to predicted, but may have a material adverse effect on our business, financial make substantial capital expenditures in our business and operations for the condition and results of operations. exploration and production of oil and natural gas reserves. We made US$303.5 million (including US$105.3 million relating to the purchase price There can be no assurance that our drilling programs will produce oil and for our Colombian acquisitions) and US$228.0 million of capital expenditures natural gas in the quantities or at the costs anticipated, or that our currently for the years ended December 31, 2012 and 2013, respectively. producing projects will not cease production, in part or entirely. Drilling programs may become uneconomic as a result of an increase in our operating In March 2014, we invested US$140 million in Brazil, subject to certain costs or as a result of a decrease in market prices for oil and natural gas. adjustments, to acquire Rio das Contas, which we financed through the Our actual operating costs or the actual prices we may receive for our oil and incurrence of a loan of US$70.5 million and cash on hand. natural gas production may differ materially from current estimates. In addition, even if we are able to continue to produce oil and gas, there In 2014, we expect our total capital expenditures, excluding the purchase can be no assurance that we will have the ability to market our oil and gas price of our Rio das Contas acquisition, to be between US$220 million to production. See “—Our inability to access needed equipment and US$250 million, of which approximately 62%, 32% and 5% will be in Chile, infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and Colombia and Brazil, respectively. We expect these capital expenditures to include the drilling of 50 to 60 new wells (approximately 40% of which natural gas production” below. we expect to be exploratory wells), as well as workovers, seismic surveys and new facility construction. In Brazil, we expect our capital expenditures Our identified potential drilling location inventories are scheduled over will consist of between US$5 million to US$7.5 million to finance in part many years, making them susceptible to uncertainties that could materially the construction of a gas compression plant in the Manatí Field (following alter the occurrence or timing of their drilling. our Rio das Contas acquisition, which closed on March 31, 2014) and approximately US$0.45 million in license fee payments to the ANP relating Our management team has specifically identified and scheduled certain to our Round 12 concessions, with the remainder for seismic surveys in potential drilling locations as an estimation of our future multi-year drilling exploration blocks in the Potiguar and Recôncavo Basins. activities on our existing acreage. As of December 31, 2013, approximately 60 of our specifically identified potential future drilling locations were attributed The actual amount and timing of our future capital expenditures may differ to proved undeveloped reserves in Chile and Colombia. These identified materially from our estimates as a result of, among other things, commodity potential drilling locations, including those without proved undeveloped prices, actual drilling results, the availability of drilling rigs and other reserves, represent a significant part of our growth strategy. In Brazil, we have equipment and services, and regulatory, technological and competitive not yet conducted seismic surveys in the seven new concession areas developments. In response to improvements in commodity prices, we may GeoPark 20F 37 increase our actual capital expenditures. We intend to finance our future regulations could change in ways that could substantially increase our costs. capital expenditures through cash generated by our operations and potential Any such liabilities, obligations, penalties, suspensions, terminations or future financing arrangements. However, our financing needs may require us regulatory changes could have a material adverse effect on our business, to alter or increase our capitalization substantially through the issuance of financial condition or results of operations. debt or equity securities or the sale of assets. In addition, the terms and conditions of the agreements under which our If our capital requirements vary materially from our current plans, we may oil and gas interests are held generally reflect negotiations with require further financing. In addition, we may incur significant financial governmental authorities and can vary significantly. These agreements take indebtedness in the future, which may involve restrictions on other financing the form of special contracts, concessions, licenses, associations or other and operating activities. These changes could cause our cost of doing types of agreements. Any suspensions, terminations or regulatory changes in business to increase, limit our ability to pursue acquisition opportunities, respect of these special contracts, concessions, licenses, associations or other reduce cash flow used for drilling and place us at a competitive disadvantage. types of agreements could have a material adverse effect on our business, A significant reduction in cash flows from operations or the availability of financial condition or results of operations. credit could materially adversely affect our ability to achieve our planned growth and operating results. Oil and gas operations contain a high degree of risk and we may not be fully insured against all risks we face in our business. We are subject to complex laws common to the oil and natural gas industry, which can have a material adverse effect on our business, financial Oil and gas exploration and production is speculative and involves a high condition and results of operations. degree of risk and hazards. In particular, our operations may be disrupted by risks and hazards that are beyond our control and that are common The oil and natural gas industry is subject to extensive regulation and among oil and gas companies, including environmental hazards, blowouts, intervention by governments throughout the world, including extensive industrial accidents, occupational safety and health hazards, technical failures, local, state and federal regulations, in such matters as the award of labor disputes, community protests or blockades, unusual or unexpected exploration and production interests, the imposition of specific exploration geological formations, flooding, earthquakes and extended interruptions and drilling obligations, allocation of and restrictions on production, price due to weather conditions, explosions and other accidents. For example, controls, required divestments of assets and foreign currency controls, and in the first half of 2013 we experienced a well control incident at our the development and nationalization, expropriation or cancellation of Chercán 1 well in the Flamenco Block in Chile with no harm to employees or contract rights. property. While we were able to bring that incident under control without injuries or environmental damage, there can be no assurance that we will We have been required in the past, and may be required in the future, not experience similar or more serious incidents in the future, which could to make significant expenditures to comply with governmental laws and result in damage to, or destruction of, wells or production facilities, personal regulations, including with respect to the following matters: • licenses, permits and other authorizations for drilling operations; injury, environmental damage, business interruption, financial losses and legal liability. • reports concerning operations; • compliance with environmental, health and safety laws and regulations; While we believe that we maintain customary insurance coverage for • drafting and implementing emergency planning; companies engaged in similar operations, we are not fully insured against all • plugging and abandonment costs; and risks in our business. In addition, insurance that we do and may carry may • taxation. contain significant exclusions from and limitations on coverage. We may elect not to obtain certain non-mandatory types of insurance if we believe that Under these laws and regulations, we could be liable for, among other the cost of available insurance is excessive relative to the risks presented. things, personal injury, property damage, environmental damage and other The occurrence of a significant event or a series of events against which we types of damage. Failure to comply with these laws and regulations may are not fully insured and any losses or liabilities arising from uninsured or also result in the suspension or termination of our operations and subject us underinsured events could have a material adverse effect on our business, to administrative, civil and criminal penalties. Moreover, these laws and financial condition or results of operations. 38 GeoPark 20F The development schedule of oil and natural gas projects is subject to cost be expensive to develop, purchase and implement and may not function overruns and delays. as expected. Such uncertainties and operating risks associated with development projects could have a material adverse effect on our business, Oil and natural gas projects may experience capital cost increases and results of operations or financial condition. overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oil field Competition in the oil and natural gas industry is intense, which makes it services. The cost to execute projects may not be properly established difficult for us to acquire properties and prospects, market oil and natural and remains dependent upon a number of factors, including the completion gas and secure trained personnel. of detailed cost estimates and final engineering, contracting and procurement costs. Development of projects may be materially adversely We compete with the major oil and gas companies engaged in the affected by one or more of the following factors: • shortages of equipment, materials and labor; exploration and production sector, including state-owned exploration and production companies that possess substantially greater financial and other • fluctuations in the prices of construction materials; resources than we do for researching and developing exploration and • delays in delivery of equipment and materials; production technologies and access to markets, equipment, labor and capital • labor disputes; • political events; • title problems; • obtaining easements and rights of way; • blockades or embargoes; • litigation; required to acquire, develop and operate our properties. We also compete for the acquisition of licenses and properties in the countries in which we operate. Our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase • compliance with governmental laws and regulations, including a greater number of properties and prospects than our financial or environmental, health and safety laws and regulations; personnel resources permit. Our competitors may also be able to offer better • adverse weather conditions; • unanticipated increases in costs; • natural disasters; • accidents; • transportation; compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. As a result of each of the aforementioned, we may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing • unforeseen engineering and drilling complications; hydrocarbons, attracting and retaining quality personnel or raising additional • environmental or geological uncertainties; and capital, which could have a material adverse effect on our business, financial • other unforeseen circumstances. Any of these events or other unanticipated events could give rise to delays in development and completion of our projects and cost overruns. 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 For example, in 2013, the drilling and completion cost for the exploratory well Argentina mentioned below. In Colombia, we partner with and sell to, and Chilco x-1 in our Flamenco Block in Chile was originally estimated at US$2.6 may from time to time compete with, Ecopetrol, as well as with privately- million, but the actual cost was approximately US$4.0 million, mainly due to owned companies such as Pacific Rubiales, Gran Tierra, Petrominerales, mechanical issues during the drilling as it was the first well drilled with a new Parex Resources Colombia Ltd. Sucursal, or Parex, and Canacol, among others. drilling rig that needed calibration at the time, leading to longer operations. In Brazil, we partner with and sell to, and may from time to time compete Delays in the construction and commissioning of projects or other technical some of the Colombian companies mentioned above, which have entered difficulties may result in future projected target dates for production into Brazil, among others. In Argentina, we compete for resources with YPF, being delayed or further capital expenditures being required. These projects as well as with privately-owned companies such as Pan American Energy, may often require the use of new and advanced technologies, which can Pluspetrol, Tecpetrol, Chevron, Wintershall, Total, Sinopec and others. with, Petrobras, privately-owned companies such as HRT, QGEP, Brasoil and GeoPark 20F 39 Our estimated oil and gas reserves are based on assumptions that may financial condition and results of operations. In addition, the shutting in of prove inaccurate. wells can lead to mechanical problems upon bringing the production back on line, potentially resulting in decreased production and increased Our oil and gas reserves estimates in Brazil (including our acquisition of Rio das remediation costs. The exploitation and sale of oil and natural gas and liquids Contas, which closed on March 31, 2014), Chile, Colombia and Argentina as of will also be subject to timely commercial processing and marketing of these December 31, 2013 are based on the D&M Reserves Report. Although classified products, which depends on the contracting, financing, building and as “proved reserves,” the reserves estimates set forth in the D&M Reserves Report operating of infrastructure by third parties. are based on certain assumptions that may prove inaccurate. D&M’s primary economic assumptions in estimates included oil and gas sales prices determined In Chile, we transport the crude oil we produce in the Fell Block by truck to according to SEC guidelines, future expenditures and other economic ENAP’s processing, storage and selling facilities at the Gregorio Refinery. assumptions (including interests, royalties and taxes) as provided by us. ENAP currently purchases all of the crude oil we produce in Chile. We rely upon the continued good condition, maintenance and accessibility of In Brazil, D&M’s estimates are also based in part on the assumption that the the roads we use to deliver the crude oil we produce. If the condition of these gas compression facility for the Manatí Field will be completed by 2015. roads were to deteriorate or if they were to become inaccessible for any Oil and gas reserves engineering is a subjective process of estimating harm our business. For example, in January 2011, social and labor unrest accumulations of oil and gas that cannot be measured in an exact way, and resulted in the roads to the Gregorio Refinery being closed for two days, and estimates of other engineers may differ materially from those set out herein. we were unable to deliver crude oil to ENAP. period of time, this could delay delivery of crude oil in Chile and materially Numerous assumptions and uncertainties are inherent in estimating quantities of proved oil and gas reserves, including projecting future rates In the Tierra del Fuego Blocks, we will temporarily depend on the existence of of production, timing and amounts of development expenditures and prices continuous ferry service to be able to transport crude oil from the island of of oil and gas, many of which are beyond our control. Results of drilling, Tierra del Fuego to the mainland. Ferry service may be adversely affected by testing and production after the date of the estimate may require revisions to weather conditions, in particular by certain combinations of strong winds and be made. For example, if we are unable to sell our oil and gas to customers, tidal currents that may occur, which may adversely affect our ability to deliver this may impact the estimate of our oil and gas reserves. Accordingly, reserves the crude oil we produce in Tierra del Fuego. In the Fell Block, we depend estimates are often materially different from the quantities of oil and gas that on ENAP-owned gas pipelines to deliver the gas we produce to Methanex, the are ultimately recovered, and if such recovered quantities are substantially sole purchaser of the gas we produce. If ENAP’s pipelines were unavailable, lower that the initial reserves estimates, this could have a material adverse this could have a materially adverse effect on our ability to deliver and sell our impact on our business, financial condition and results of operations. product to Methanex, which could have a material adverse effect on our gas sales. In addition, gas production in some areas in the Tierra del Fuego Blocks Our inability to access needed equipment and infrastructure in a timely and the Otway and Tranquilo Blocks could require us to build a new network manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural of gas pipelines in order for us to be able to deliver our product to market, which could require us to make significant capital investments. gas production. Our ability to market our oil and natural gas production depends logistics issues and limited storage capacity, which cause delays in delivery substantially on the availability and capacity of processing facilities, oil and transfer of title of crude oil. Such capacity issues in Colombia may require tankers, transportation facilities (such as pipelines, crude oil unloading us to transport crude from our Colombian operations via truck, which may stations and trucks) and other necessary infrastructure, which may be owned increase the costs of those operations. Road infrastructure is limited in and operated by third parties. Our failure to obtain such facilities on certain areas in which we operate, and certain communities have used and acceptable terms or on a timely basis could materially harm our business. may continue to use road blockages, which can sometimes interfere with In Colombia, producers of crude oil have suffered from tanker transportation We may be required to shut in oil and gas wells because access to our operations in these areas. transportation or processing facilities may be limited or unavailable when needed. If that were to occur, then we would be unable to realize revenue While Brazil has a well-developed network of hydrocarbon pipelines, from those wells until arrangements were made to deliver the production storage and loading facilities, we may not be able to access these facilities to market, which could cause a material adverse effect on our business, when needed. Pipeline facilities in Brazil are often full and seasonal capacity 40 GeoPark 20F restrictions may occur, particularly in natural gas pipelines. Our failure participation interest of 10%. See “Item 4. Information on the Company—B. to secure transportation or access to pipelines or other facilities once we Business overview—Health, safety and environmental matters—Other commence operations in the seven concessions we were awarded in Brazil regulation of the oil and gas industry—Brazil.” on acceptable terms or on a timely basis could materially harm our business. Additionally, offshore drilling generally requires more time and more Our use of seismic data is subject to interpretation and may not accurately advanced drilling technologies, involving a higher-risk of technological failure identify the presence of oil and natural gas. and usually higher drilling costs. Offshore projects often lack proximity to existing oilfield service infrastructure, necessitating significant capital Even when properly used and interpreted, seismic data and visualization investment in flow line infrastructure before we can market the associated oil techniques are tools only used to assist geoscientists in identifying subsurface or gas of a commercial discovery, increasing both the financial and structures as well as eventual hydrocarbon indicators, and do not enable operational risk involved with these operations. Because of the lack and high the interpreter to know whether hydrocarbons are, in fact, present in those cost of infrastructure, some offshore reserve discoveries may never be structures. In addition, the use of seismic and other advanced technologies produced economically. requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of these expenditures. Because of these Further, because we are not the operator of our offshore fields, all of these uncertainties associated with our use of seismic data, some of our drilling risks may be heightened since they are outside of our control. Following activities may not be successful or economically viable, and our overall our Rio das Contas acquisition, which closed on March 31, 2014, we obtained drilling success rate or our drilling success rate for activities in a particular a 10% interest in the Manatí Field which limits our operating flexibility in area could decline, which could have a material adverse effect on us. such offshore fields. See “—We are not, and may not be in the future, the sole Through our Rio das Contas acquisition, which closed on March 31, 2014, the future, hold all of the working interests in certain of our licensed areas. we will begin to face operational risks relating to offshore drilling that we have not faced in the past. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non- owner or operator of all of our licensed areas and do not, and may not in operated and, to an extent, any non-wholly-owned, assets.” To date, we have operated solely as an onshore oil and gas exploration and production company. However, our operations in the Manatí Field in Brazil We may suffer delays or incremental costs due to difficulties in negotiations may include shallow-offshore drilling activity in two concession areas in with landowners and local communities where our reserves are located. the Camamu-Almada Basin, which we expect will continue to be operated by Petrobras. Access to the sites where we operate requires agreements (including, for example, assessments, rights of way and access authorizations) with Offshore operations are subject to a variety of operating risks and laws and landowners and local communities. If we are unable to negotiate agreements regulations, including among other things, with respect to environmental, health and safety matters, specific to the marine environment, such as with landowners, we may have to go to court to obtain access to the sites of our operations, which may delay the progress of our operations at such capsizing, collisions and damage or loss from hurricanes or other adverse sites. In Chile, for example, we have negotiated the necessary agreements for weather conditions. These conditions can cause substantial damage to many of our current operations in the Magallanes Basin. In the Tierra del facilities and interrupt production. As a result, we could incur substantial Fuego Blocks, although we have successfully negotiated access to our sites, liabilities, compliance costs, fines or penalties that could reduce or eliminate any future disputes with landowners or court proceedings may delay our the funds available for exploration, development or leasehold acquisitions, operations in Tierra del Fuego Blocks. In Brazil, in the event that social unrest or result in loss of equipment and properties. For example, the Manatí Field that occurred in 2013 continues or intensifies, this may lead to delays or has been subject to administrative infraction notices, which have resulted damage relating to our ability to operate the assets we have acquired or may in fines against Petrobras in an aggregate amount of US$12.5 million, acquire in our Brazil Acquisitions. all of which are pending a final decision of the Brazilian Institute for the Environment and Natural Renewable Resources ( Instituto Brasileiro do Meio- In Colombia, although we have agreements with many landowners and are Ambiente e dos Recursos Naturais Renováveis ), or IBAMA. Although the in negotiations with others, we expect our costs to increase following current administrative fines were filed against Petrobras, as a party to the concession and future negotiations regarding access to our blocks, as the economic agreement governing the Manatí Field, Rio das Contas may be liable up to its expectations of landowners have generally increased, which may delay access GeoPark 20F 41 to existing or future sites. In addition, the expectations and demands of subsequently relinquished all areas of the Tranquilo Block, except for an area local communities on oil and gas companies operating in Colombia have of 92,417 gross acres, where we declared four hydrocarbons discoveries. increased in the wake of recent changes to the royalty regime in Colombia. Additionally, on April 10, 2013, we voluntarily and formally announced to the As a result, local communities have demanded that oil and gas companies Chilean Ministry of Energy our decision not to proceed with the second invest in remediating and improving public access roads, compensate them exploratory period and to terminate the exploration phase under the Otway for any damages related to use of such roads and, more generally, invest Block CEOP, and subsequently relinquished all areas of the Otway Block, in infrastructure that was previously paid for with public funds. Due to these except for two areas totaling 49,421 gross acres in which we have declared circumstances, oil and gas companies in Colombia, including us, are now hydrocarbons discoveries. See “Item 4. Information on the Company—B. dealing with increasing difficulties resulting from instances of social unrest, Business overview—Our operations—Operations in Argentina—Del Mosquito temporary road blockages and conflicts with landowners. For example, in Block” and “Item 4. Information on the Company—B. Business overview—Our August 2013, our access to Llanos 34 Block was blocked by the local operations—Operations in Chile—Otway and Tranquilo Blocks.” community due to national social unrest in Colombia, resulting in our suspension of production for a period of five days. For additional details regarding the status of our operations with respect to our various special contracts and concession agreements, see “Item 4. There can be no assurance that disputes with landowners and local Information on the Company—B. Business overview—Our operations.” communities will not delay our operations or that any agreements we reach with such landowners and local communities in the future will not require A significant amount of our reserves and production have been derived us to incur additional costs, thereby materially adversely affecting our from our operations in one block, the Fell Block. business, financial condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected For the year ended December 31, 2013, the Fell Block contained 53% of government to restrict our access to the sites of our operations, which may our net proved reserves and generated 51.5% of our total production. have a material adverse effect on our operations at such sites. On a pro forma basis (including the Rio das Contas Acquisition), for the year Under the terms of some of our various CEOPs, E&P Contracts and proved reserves and generated 41% of our total production. While the concession agreements, we are obligated to drill wells, declare any acquisitions of Winchester, Luna and Cuerva in Colombia and our expansion discoveries and file periodic reports in order to retain our rights into Brazil mean that the Fell Block is a less significant component of our and establish development areas. Failure to meet these obligations overall business than it has been in the past, we nonetheless expect may result in the loss of our interests in the undeveloped parts of that the Fell Block will continue to be responsible for a significant portion ended December 31, 2013, the Fell Block contained 38% of our net our blocks or concession areas. of our reserves and production. Any government intervention, impairment or disruption of our production due to factors outside of our control or In order to protect our exploration and production rights in our license areas, any other material adverse event in our operations in the Fell Block would we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified have a material adverse effect on our business, financial condition and results of operations. in our various CEOPs, E&P Contracts and concession agreements, our interests in the undeveloped parts of our license areas may lapse. Should the prospects Our contracts in obtaining rights to explore and develop oil and natural we have identified under these contracts and agreements yield discoveries, gas reserves are subject to contractual expiration dates and operating we may face delays in drilling these prospects or be required to relinquish conditions, and our CEOPs, E&P Contracts and concession agreements are these prospects. The costs to maintain or operate the CEOPs, E&P Contracts subject to early termination in certain circumstances. and concession agreements over such areas may fluctuate and may increase significantly, and we may not be able to meet our commitments under such Under certain of the CEOPs, E&P Contracts and concession agreements to contracts and agreements on commercially reasonable terms or at all, which which we are or may in the future become parties, we are or may become may force us to forfeit our interests in such areas. For example, on January 17, subject to guarantees to perform our commitments and/or to make payment 2013, we voluntarily and formally announced to the Chilean Ministry of for other obligations, and we may not be able to obtain financing for all such Energy our decision not to proceed with the second exploration period and obligations as they arise. If such obligations are not complied with when to terminate the exploration phase under the Tranquilo Block CEOP, and due, in addition to any other remedies that may be available to other parties, 42 GeoPark 20F this could result in cancelation of our CEOPs, E&P Contracts and concession In addition, according to the Chilean Constitution, Chile is entitled to agreements or dilution or forfeiture of interests held by us. As of December expropriate our rights in our CEOPs for reasons of public interest. Although 31, 2013, the aggregate outstanding amount of this potential liability for Chile would be required to indemnify us for such expropriation, there can guarantees was approximately US$87.5 million, mainly relating to guarantees be no assurance that any such indemnification will be paid in a timely manner of our minimum work program for the Tierra del Fuego Blocks and, to a or in an amount sufficient to cover the harm to our business caused by such significantly lesser extent, our minimum work programs for our Colombian expropriation. operations and the ten Brazilian concession areas. 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 can do results in the immediate enforcement of monetary guaranties against us so on terms that are acceptable to us or at all. and may result in an action for damages by the ANH and/or a restriction on our ability to engage in contracts with the Colombian government during a In particular, in Chile, our CEOPs provide for early termination by Chile in certain period of time. See “Item 4. Information on the Company—B. Business certain circumstances, depending upon the phase of the CEOP. For example, overview—Significant agreements—Colombia—E&P Contracts.” pursuant to the Fell Block CEOP, under which we are in the exploitation phase, Chile may terminate the CEOP if (i) we stop performing any of the In Brazil, concession agreements generally may be renewed, at the ANP’s substantial obligations assumed under the Fell Block CEOP without cause and discretion, for an additional period equivalent to the original concession do not cure such nonperformance pursuant to the terms of the concession, period, provided that a renewal request is made at least 12 months prior following notice of breach or (ii) our oil activities are interrupted for more to the termination of the concession agreement and there has not been a than three years due to force majeure circumstances (as defined in the breach of the terms of the concession agreement. We expect that all our Fell Block CEOP). If the Fell Block CEOP is terminated in the exploitation phase, concession agreements will provide for early termination in the event of: we will have to transfer to Chile, free of charge, any productive wells and (i) government expropriation for reasons of public interest; (ii) revocation of related facilities, provided that such transfer does not interfere with our the concession pursuant to the terms of the concession agreement; or (iii) abandonment obligations and excluding certain pipelines and other assets. failure by us or our partners to fulfill all of our respective obligations under See “Item 4. Information on the Company—B. Business overview— the concession agreement (subject to a cure period). Administrative or Significant agreements—Chile—CEOPs—Fell Block CEOP.” If the CEOP is monetary sanctions may also be applicable, as determined by the ANP, which terminated early due to a breach of our obligations, we may not be entitled shall be imposed based on applicable law and regulations. In the event of to compensation. Additionally, our CEOPs for the Tierra del Fuego Blocks, early termination of a concession agreement, the compensation to which which are in the exploration phase, may be subject to early termination we are entitled may not be sufficient to compensate us for the full value of during this phase under circumstances including (i) a failure by us to comply with minimum work commitments at the termination of any exploration our assets. Moreover, in the event of early termination of any concession agreement due to failure to fulfill obligations thereunder, we may be subject period, (ii) a failure to communicate our intention to proceed with the next to fines and/or other penalties. exploration period 30 days prior to its termination, (iii) a failure to provide the Chilean Ministry of Energy requisite performance bonds, (iv) a voluntary Early termination or nonrenewal of any CEOP, E&P Contract or concession relinquishment by us of all areas under the CEOP, (v) a failure by us to meet agreement could have a material adverse effect on our business, financial the requirements to enter into the exploitation phase upon the termination situation or results of operations. 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 Tierra We sell almost all of our natural gas in Chile to a single customer, who has del Fuego Block CEOPs are terminated within the exploration phase, we are in the past temporarily idled its principal facility. released from all obligations under the CEOPs, except for obligations regarding the abandonment of fields, if any. See “Item 4. Information on the For the year ended December 31, 2013, almost all of our natural gas sales Company—B. Business overview—Significant agreements—Chile—CEOPs.” in Chile were made to Methanex under a long-term contract, or the Methanex There can be no assurance that the early termination of any of our CEOPs Gas Supply Agreement, which expires on April 30, 2017. Sales to Methanex would not have a material adverse effect on us. GeoPark 20F 43 represented 6.7% of our total revenues for the year ended December 31, from us, there can be no assurance that we would be able to sell our gas 2013. Methanex also buys gas from ENAP and a consortium that Methanex production to other parties or on similar terms, which could have a material has formed with ENAP. While our contract with Methanex requires it to adverse effect on our business, financial condition and results of operations. purchase the entirety of our production of natural gas from the Fell Block, and requires us to sell to Methanex all of our natural gas production from Fell We may not be able to meet delivery requirements under the agreement Block, subject to minor exceptions, if Methanex were to decrease or cease for the sale of our natural gas in Chile. its purchase of gas from us, this would have a material adverse effect on our revenues derived from the sale of gas. In addition, there can be no assurance Under the Methanex Gas Supply Agreement, Methanex has committed to that we will be able to extend or renew our contract with Methanex past purchasing, and we have committed to selling, all of the gas that we produce April 30, 2017, which could have a material adverse effect on our business, in the Fell Block (subject to certain exceptions, including reasonable financial condition and results of operations. quantities required to maintain our operations and quantities that we might be required to pay in kind to Chile), with a minimum volume commitment Methanex has two methanol producing facilities at its Cabo Negro production which is defined by us on an annual basis. The agreement contains monthly facility, near the city of Punta Arenas in southern Chile. However, after DOP obligations, which require us to deliver in a given month the minimum Argentine natural gas producers cut off exports to Chile in 2007, Methanex gas committed for that month or pay a deficiency penalty to Methanex, with had to stop production at all but one of these facilities, and began to rely a threshold of 90% of the committed quantities of gas. The agreement also completely on local suppliers of natural gas, including ENAP, for its contains monthly TOP obligations, which apply when our committed volume operations. Since 2009, however, the amount of natural gas that ENAP has for a given month exceeds 35.3 mcfpd, and require Methanex to take in such been able to provide to Methanex has been decreasing, as ENAP has given month the minimum gas volume committed for such period or face higher priority to providing natural gas to the city of Punta Arenas. Although we TOP obligations in later months, with a threshold of 90% of the committed sell all the natural gas we produce in the Fell Block to Methanex, and supplied quantities. These DOP and TOP obligations are subject to make-up provisions approximately 50% of all the natural gas consumed by Methanex before without penalty, for any delivery or off-take deficiencies accrued, in the three the idling of its plant in April 2013, we alone cannot supply Methanex with all months following the month where delivery or off-take requirements were the natural gas it requires for its operations. not met. The plant was idled due to an anticipated insufficient supply of natural gas. On August 30, 2013, we signed an amendment to the Methanex Gas Supply The supply of natural gas decreased during the winter months of 2013 due to Agreement, pursuant to which Methanex committed, for a period of six the increase in seasonal gas demand from the city of Punta Arenas in the months commencing September 15, 2013, to purchase an increased volume, Magallanes region, to which gas producers, including GeoPark, gave priority, in a total amount of 400,000 SCM/d per month (subject to reduction for delivering gas to the city through ENAP. Methanex continued to purchase deliveries above 200,000 SCM/d to Methanex or ENAP made between April from us the volume of gas it requires for the plant’s operation during the 29 and September 15, 2013), incorporating an additional premium to the idling, and we signed an amendment to the agreement, pursuant to which Methanex pay us a premium over the current gas price for deliveries gas price depending on the volumes delivered. The amendment also provides for temporary DOP and TOP thresholds of 100% and 50%, respectively. exceeding certain volumes of gas, in the period immediately following The amendment has been extended until April 30 2014. Therefore, we are the Methanex plant’s startup, which occurred on September 23, 2013. See currently committed to providing to Methanex a monthly volume of gas of “Item 4. Information on the Company—B. Business overview—Marketing 0.4 bcf until April 30, 2014. and Delivery Commitments—Chile.” Methanex has been making investments aimed at lowering its plant’s minimum gas requirements during the idling, For example, in 2012, we failed to meet this adjusted volume for each of the so that the plant is currently able to function with 21.2 mcfpd of gas. months of April through December of 2012, such that we accrued US$1.7 million in DOP payments owed to Methanex under the Methanex Gas Supply However, there can be no assurance that Methanex will continue to purchase Agreement, all of which had been paid as of September 30, 2013. the committed volume of gas from us or that its efforts to reduce the risk of future shutdowns will be successful, which could have a material adverse There can be no assurance that we or Methanex will be able to meet effect on our gas revenues. Additionally, there can be no assurance that our respective DOP and TOP obligations under the Methanex Gas Supply Methanex will have sufficient supplies of gas to operate its plant and continue Agreement or that we will not incur additional deficiency penalties, to purchase our gas production. If Methanex were to cease purchasing in the future. 44 GeoPark 20F We are not, and may not be in the future, the sole owner or operator of This limited ability to exercise control over the operations on some of our all of our licensed areas and do not, and may not in the future, hold all license areas may cause a material adverse effect on our financial condition of the working interests in certain of our licensed areas. Therefore, and results of operations. we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated LGI, our strategic partner in Chile and Colombia, may sell its interest in and, to an extent, any non-wholly-owned, assets. our Chilean and Colombian operations to a third party or may not consent to our taking certain actions. As of the date of this annual report, we are not the sole owner or operator of the Llanos 17, Llanos 32 and Jagüeyes 3432 A Blocks in Colombia, which We have a strategic partnership with LGI, which has a 20% equity interest in represented 3% of our total production as of December 31, 2013 (on a pro GeoPark Chile, a 14% direct equity interest in GeoPark TdF (31.2% taking into forma basis, accounting for our Rio das Contas acquisition). In Brazil, the terms account direct and indirect participation through GeoPark Chile) and a 20% of our Rio das Contas acquisition are such that we are not the sole owner or equity interest in GeoPark Colombia, through its equity interest in GeoPark operator of the BCAM-40 Concession, which represented approximately Colombia Cooperatie. Our shareholders’ agreements with LGI in each of 21% of our total production for the year ended December 31, 2013 (on a pro Chile and Colombia provides that we have a right of first offer if LGI decides forma basis, accounting for our Rio das Contas acquisition). to sell any of its interest in GeoPark Chile or GeoPark Colombia. There can be no assurance, however, that we will have the funds to purchase LGI’s In addition, the terms of the joint venture agreements or association interest in Chile and/or Colombia and that LGI will not decide to sell its shares agreements governing our other partners’ interests in almost all of the blocks to a third party whose interests may not be aligned with ours. that are not wholly-owned or operated by us require that certain actions be approved by supermajority vote. The terms of our other current or future In addition, our shareholders’ agreements with LGI in Chile and Colombia license or venture agreements may require at least the majority of working contain provisions that require GeoPark Chile and GeoPark Colombia to interests to approve certain actions. As a result, we may have limited ability obtain LGI’s consent before undertaking certain actions. For example, under to exercise influence over operations or prospects in the blocks operated the terms of the shareholders’ agreement with LGI in Colombia, LGI must by our partners, or in blocks that are not wholly-owned or operated by us. A approve GeoPark Colombia’s annual budget and work programs and breach of contractual obligations by our partners who are the operators of mechanisms for funding any such budget or program, the entering into any such blocks could eventually affect our rights in exploration and production borrowings other than those provided in an approved budget or incurred contracts in our blocks in Colombia. Our dependence on our partners could in the ordinary course of business to finance working capital needs, the prevent us from realizing our target returns for those discoveries or prospects. granting of any guarantee or indemnity to secure liabilities of parties other than those of our Colombian subsidiaries and disposing of any material assets Moreover, as we are not the sole owner or operator of all of our properties, other than those provided for in an approved budget and work program. we may not be able to control the timing of exploration or development Similarly, in Chile, pursuant to the terms of our shareholders’ agreements with activities or the amount of capital expenditures and may therefore not be able to carry out our key business strategies of minimizing the cycle time 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 decision between discovery and initial production at such properties. The success to terminate or permanently or indefinitely suspend operations in or and timing of exploration and development activities operated by our surrender our blocks in Chile (other than as required under the terms of the partners will depend on a number of factors that will be largely outside of relevant CEOP for such blocks); selling our blocks in Chile to our affiliates; our control, including: • the timing and amount of capital expenditures; • the operator’s expertise and financial resources; • approval of other block partners in drilling wells; making any change to the dividend, voting or other rights that would give preference to or discriminate against the shareholders of these companies; entering into certain related party transactions; and creating a security interest over our blocks in Chile (other than in connection with a financing • the scheduling, pre-design, planning, design and approvals of activities that benefits our Chilean subsidiaries). and processes; • selection of technology; and Additionally, pursuant to our agreements with LGI in Chile, we and LGI have • the rate of production of reserves, if any. 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 of cash to meet anticipated future investments, costs and GeoPark 20F 45 obligations, and pursuant to our agreement with LGI in Colombia, we and related to the assets or management of the companies and operations LGI have agreed to vote our common shares or otherwise cause GeoPark we have acquired, such as in Colombia or Brazil, or other companies Colombia to declare dividends only after allowing for retentions of cash or operations we may acquire in future, will not arise in future, and these for approved work programs and budgets and capital adequacy requirements problems could have a material adverse effect on our business, financial of GeoPark Colombia, working capital requirements, banking covenants condition and results of operations. associated with any loan entered into by GeoPark Colombia or our other Colombian subsidiaries and operational requirements. Our inability to obtain Significant acquisitions and other strategic transactions may involve other LGI’s consent or a delay by LGI in granting its consent may restrict or delay risks, including: the ability of GeoPark Chile, GeoPark TdF or GeoPark Colombia to take certain • diversion of our management’s attention to evaluating, negotiating and actions, which may have an adverse effect on our operations in such integrating significant acquisitions and strategic transactions; countries and on our business, financial condition and results of operations. • challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with Acquisitions that we have completed and any future acquisitions, strategic those of ours while carrying on our ongoing business; investments, partnerships or alliances could be difficult to integrate and/or • contingencies and liabilities that could not be or were not identified during identify, could divert the attention of key management personnel, disrupt the due diligence process, including with respect to possible deficiencies our business, dilute stockholder value and adversely affect our financial in the internal controls of the acquired operations; and results, including impairment of goodwill and other intangible assets. • challenge of attracting and retaining personnel associated with acquired One of our principal business strategies includes acquisitions of properties, operations. prospects, reserves and leaseholds and other strategic transactions, including If we fail to realize the benefits we anticipate from an acquisition, our results in jurisdictions in which we do not currently operate. The successful of operations may be adversely affected. acquisition and integration of producing properties, including our acquisitions of Winchester, Luna and Cuerva in Colombia and our Brazil It is also possible that we may not identify suitable acquisition targets Acquisitions, requires an assessment of several factors, including: or strategic investment, partnership or alliance candidates. Our inability to • recoverable reserves; • future oil and natural gas prices; • development and operating costs; and identify suitable acquisition targets, strategic investments, partners or alliances, or our inability to complete such transactions, may negatively affect our competitiveness and growth opportunities. Moreover, if we fail to • potential environmental and other liabilities. properly evaluate acquisitions, alliances or investments, we may not achieve the anticipated benefits of any such transaction and we may incur costs in The accuracy of these assessments is inherently uncertain. In connection excess of what we anticipate. with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review and the review of advisors and independent reserves engineers will not reveal Future acquisitions financed with our own cash could deplete the cash and working capital available to adequately fund our operations. We may also all existing or potential problems nor will it permit us or them to become finance future transactions through debt financing, the issuance of our equity sufficiently familiar with the properties to fully assess their deficiencies and securities, existing cash, cash equivalents or investments, or a combination potential recoverable reserves. Inspections may not always be performed of the foregoing. Acquisitions financed with the issuance of our equity on every well, and environmental conditions are not necessarily observable securities could be dilutive, which could affect the market price of our stock. even when an inspection is undertaken. We, advisors or independent reserves Acquisitions financed with debt could require us to dedicate a substantial engineers may apply different assumptions when assessing the same field. portion of our cash flow to principal and interest payments and could subject Even when problems are identified, the seller may be unwilling or unable us to restrictive covenants. to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental The PN-T-597 concession is subject to an injunction and may not close. liabilities and acquire properties on an “as is” basis. Even in those circumstances in which we have contractual indemnification rights for In Brazil, GeoPark Brazil is currently a party to a legal proceeding related to pre-closing liabilities, it remains possible that the seller will not be able the concession agreement of Block PN-T-597 that the ANP initially awarded to fulfill its contractual obligations. There can be no assurance that problems to GeoPark Brazil in the 12th oil and gas bidding round. As a result of a 46 GeoPark 20F class action filed by the Federal Prosecutor’s Office, an injunction was issued The development of our proved undeveloped reserves may take longer by a Brazilian Federal Court against the ANP, the Federal Government and and may require higher levels of capital expenditures than we currently GeoPark Brazil on December 13, 2013. Due to the injunction GeoPark anticipate. Therefore, our proved undeveloped reserves ultimately Brazil could not proceed to execute the concession agreement, and cannot may not be developed or produced. do so until the injunction is lifted. According to the terms of the Court’s injunction, the ANP will first need to take certain actions, such as conducting As of December 31, 2013, only approximately 42% of our net proved reserves studies that prove that drilling unconventional resources will not contaminate have been developed. Development of our undeveloped reserves may the dams and aquifers in the region. On February 21, 2014, GeoPark Brazil take longer and require higher levels of capital expenditures than we currently requested that the board of the ANP suspend the execution of the concession anticipate. Additionally, delays in the development of our reserves or increases agreement (which entails delivery of the financial guarantee and performance in costs to drill and develop such reserves will reduce the standardized measure guarantee and payment of the signing bonus) for six months with a possible value of our estimated proved undeveloped reserves and future net revenues extension of an additional six months, or until a firm court decision is reached estimated for such reserves, and may result in some projects becoming that does not prevent GeoPark Brazil from entering into the concession uneconomic, causing the quantities associated with these uneconomic projects agreement. On April 16, 2014, the ANP’s Board enacted a resolution stating to no longer be classified as reserves. For example, in Argentina, although we that all proceedings related to the award of the concession of Block PN-T-597 had production in the blocks in which we have a working interest, D&M to GeoPark Brazil were suspended. determined that there were no reserves in these blocks as of December 31, 2013. This was due to the uneconomic status of the reserves, given the proximity to There can be no assurance that we will be able to extend the deadlines the end of the concessions for these blocks, which does not allow for future associated with the entry into the Concession Contract or enter into the capital investment in the blocks. There can be no assurance that we will not concession agreement. See “Item 8—Financial Information—A. Consolidated experience similar delays or increases in costs to drill and develop our reserves in statements and other financial information—Legal proceedings.” the future, which could result in further reclassifications of our reserves. The present value of future net revenues from our proved reserves will We are exposed to the credit risks of our customers and any material not necessarily be the same as the current market value of our estimated nonpayment or nonperformance by our key customers could adversely oil and natural gas reserves. affect our cash flow and results of operations. You should not assume that the present value of future net revenues from Our customers may experience financial problems that could have our proved reserves is the current market value of our estimated oil and a significant negative effect on their creditworthiness. Severe financial natural gas reserves. For the year ended December 31, 2013, we have based problems encountered by our customers could limit our ability to collect the estimated discounted future net revenues from our proved reserves amounts owed to us, or to enforce the performance of obligations on the 12 month unweighted arithmetic average of the first-day-of-the- owed to us under contractual arrangements. month price for the preceding 12 months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as: The combination of declining cash flows as a result of declines in commodity • actual prices we receive for oil and natural gas; prices, a reduction in borrowing basis under reserves-based credit • actual cost of development and production expenditures; facilities and the lack of availability of debt or equity financing may result • the amount and timing of actual production; and in a significant reduction of our customers’ liquidity and limit their ability to • changes in governmental regulations, taxation or the taxation invariability make payments or perform on their obligations to us. provisions in our CEOPs. Furthermore, some of our customers may be highly leveraged, and, in any The timing of both our production and our incurrence of expenses in event, are subject to their own operating expenses. Therefore, the risk we connection with the development and production of oil and natural gas face in doing business with these customers may increase. Other customers properties will affect the timing and amount of actual future net revenues may also be subject to regulatory changes, which could increase the risk of from proved reserves, and thus their actual value. In addition, the 10% defaulting on their obligations to us. Financial problems experienced by discount factor we use when calculating discounted future net revenues our customers could result in the impairment of our assets, a decrease in our may not be the most appropriate discount factor based on interest rates in operating cash flows and may also reduce or curtail our customers’ future effect from time to time and risks associated with us or the oil and natural use of our products and services, which may have an adverse effect on our gas industry in general. revenues and may lead to a reduction in reserves. GeoPark 20F 47 We may not have the capital to develop our unconventional oil and where we conduct our activities, thereby increasing our turnover rate. gas resources. There is strong ongoing competition in our industry to hire employees in operational, technical and other areas, and the supply of qualified employees We have identified opportunities for analyzing the potential of is limited in the regions where we operate and throughout Latin America unconventional oil and gas resources in some of our blocks and concessions generally. The loss of any of our executive officers or other key employees of in Chile, Colombia, Brazil and Argentina. Our ability to develop this potential our technical team or our inability to hire and retain new qualified personnel depends on a number of factors, including the availability of capital, could have a material adverse effect on us. seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, Unfavorable credit and market conditions, such as the global financial services and personnel and drilling results. In addition, as we have no crisis that began in 2008, have affected and could continue to affect previous experience in drilling and exploiting unconventional oil and gas negatively the economies of the countries in which we operate and may resources, the drilling and exploitation of such unconventional oil and negatively affect our liquidity, business, and results of operations. gas resources depends on our ability to acquire the necessary technology, to hire personnel and other support needed for extraction or to obtain Global financial crises and related turmoil in the global financial system financing and venture partners to develop such activities. Because of these have had, and may continue to have, a negative impact on our business, uncertainties, we cannot give any assurance as to the timing of these financial condition and results of operations. The lingering effects of the activities, or that they will ultimately result in the realization of proved global credit crisis that began in 2008 and of financial crises generally reserves or meet our expectations for success. on our customers and on us cannot be predicted. Persistent uncertainty in Our operations are subject to operating hazards, including extreme Europe and the United States, may affect our ability to access the credit or weather events, which could expose us to potentially significant losses. capital markets at a time when we would need financing, which could have an impact on our flexibility to react to changing economic and business Our operations are subject to potential operating hazards, extreme weather conditions. Any of the foregoing factors or a combination of these factors conditions and risks inherent to drilling activities, seismic registration, could have an adverse effect on our liquidity, results of operations and international credit markets, exacerbated by the sovereign debt crises in exploration, production, development and transportation and storage of financial condition. crude oil, such as explosions, fires, car and truck accidents, floods, labor disputes, social unrest, community protests or blockades, guerilla attacks, We and our operations are subject to numerous environmental, health security breaches, pipeline ruptures and spills and mechanical failure of and safety laws and regulations which may result in material liabilities equipment at our or third-party facilities. Any of these events could have and costs. a material adverse effect on our exploration and production operations, or disrupt transportation or other process-related services provided by our We and our operations are subject to various international, foreign, federal, third-party contractors. state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants We are highly dependent on certain members of our management and into the ground, air or water; the generation, storage, handling, use, technical team, including our geologists and geophysicists, and on our transportation and disposal of regulated materials; and human health and ability to hire and retain new qualified personnel. safety. Our operations are also subject to certain environmental risks that are inherent in the oil and gas industry and which may arise unexpectedly The ability, expertise, judgment and discretion of our management and our and result in material adverse effects on our business, financial condition technical and engineering teams are key in discovering and developing oil and results of operations. Breach of environmental laws, as well as impacts and natural gas resources. Our performance and success are dependent to a on natural resources and unauthorized use of such resources, could large extent upon key members of our management and exploration team, result in environmental administrative investigations and/or lead to the and their loss or departure would be detrimental to our future success. In termination of our concessions and contracts. Other potential consequences addition, our ability to manage our anticipated growth depends on our ability include fines and/or criminal or civil environmental actions. For instance, to recruit and retain qualified personnel. Our ability to retain our employees non-governmental organizations seeking to preserve the environment may is influenced by the economic environment and the remote locations of bring actions against us or other oil and gas companies in order to, among our exploration blocks, which may enhance competition for human resources other things, halt our activities in any of the countries in which we operate 48 GeoPark 20F or require us to pay fines. Additionally, in Colombia, recent rulings have might require us to remediate contamination, or retrofit facilities, at provided that environmental licenses are administrative acts subject to class substantial cost. We also could be held liable for any and all consequences actions that could eventually result in their cancellation, with potential arising out of human exposure to such substances or for other damage adverse impacts on our E&P Contracts. resulting from the release of hazardous substances to the environment, property or to natural resources, or affecting endangered species or sensitive We are required to obtain environmental permits from governmental environmental areas. Environmental laws and regulations also require that authorities for our operations, including drilling permits for our wells. wells be plugged and sites be abandoned and reclaimed to the satisfaction We have not been and may not be at all times in complete compliance with of the relevant regulatory authorities. We are currently required to, and in these permits and the environmental and health and safety laws and the future may need to, plug and abandon sites in certain blocks in each of regulations to which we are subject. If we violate or fail to comply with such the countries in which we operate, which could result in substantial costs. requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or In addition, we expect continued and increasing attention to climate termination of our operations. If we fail to obtain, maintain or renew permits change issues. Various countries and regions have agreed to regulate in a timely manner or at all (such as due to opposition from partners, emissions of greenhouse gases including methane (a primary component community or environmental interest groups, governmental delays or any of natural gas) and carbon dioxide (a byproduct of oil and natural gas other reasons) or if we face additional requirements due to changes in combustion). The regulation of greenhouse gases and the physical impacts applicable laws and regulations, our operations could be adversely affected, of climate change in the areas in which we, our customers and the end- impeded, or terminated, which could have a material adverse effect on our users of our products operate could adversely impact our operations and business, financial condition or results of operations. Some environmental the demand for our products. licenses related to operation of the Manatí Field production system and natural gas pipeline have expired. However, the operator submitted timely a request Environmental, health and safety laws and regulations are complex and for renewal of those licenses and as such this operation is not in default as change frequently, and have tended to become increasingly stringent long as the regulator does not state its final position on the renewal. over time. Our costs of complying with current and future climate change, environmental, health and safety laws, the actions or omissions of our We, as the owner, shareholder or the operator of certain of our past, current partners and third-party contractors and our liabilities arising from releases and future discoveries and prospects, could be held liable for some or all of, or exposure to, regulated substances may adversely affect our results environmental, health and safety costs and liabilities arising out of our actions of operations and financial condition. See “Item 4. Information on the and omissions as well as those of our block partners, third-party contractors, Company—B. Business overview—Health, safety and environmental matters” predecessors or other operators. To the extent we do not address these and “Item 4. Information on the Company—B. Business overview—Industry costs and liabilities or if we do not otherwise satisfy our obligations, our and regulatory framework.” operations could be suspended, terminated or otherwise adversely affected. We have also contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could contract with third parties with unsatisfactory environmental, health increase the future costs of doing business, cause delays or impede our and safety records or that our contractors may be unwilling or unable to plans, and materially adversely affect our operations. cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of the acts or Hydraulic fracturing of unconventional oil and gas resources is a process omissions of our contractors, which could have a material adverse effect on that involves injecting water, sand, and small volumes of chemicals into the our results of operations and financial condition. wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate a higher flow of hydrocarbons into the wellbore. Releases of regulated substances may occur and can be significant. Under We are contemplating such use of hydraulic fracturing in the production of certain environmental laws and regulations applicable to us in the countries oil and natural gas from certain reservoirs, especially shale formations. in which we operate, we could be held responsible for all of the costs We currently are not aware of any proposals in Chile, Colombia, Brazil or relating to any contamination at our past and current facilities and at any Argentina to regulate hydraulic fracturing beyond the regulations already third-party waste disposal sites used by us or on our behalf. Pollution in place. However, various initiatives in other countries with substantial shale resulting from waste disposal, emissions and other operational practices gas resources have been or may be proposed or implemented to, among GeoPark 20F 49 other things, regulate hydraulic fracturing practices, limit water withdrawals Furthermore, on March 28, 2014, our Brazilian subsidiary that acquired Rio das and water use, require disclosure of fracturing fluid constituents, restrict Contas entered into a US$70.5 million loan to finance part of the acquisition. which additives may be used, or implement temporary or permanent bans This loan includes covenants restricting dividend payments to us. For a on hydraulic fracturing. If any of the countries in which we operate adopts description, see “Item 5. Operating and Financial Review and Prospects—B. similar laws or regulations, which is something we cannot predict right now, Liquidity and Capital Resources—Indebtedness—Rio das Contas Credit such adoption could significantly increase the cost of, impede or cause Facility. delays in the implementation of any plans to use hydraulic fracturing for unconventional oil and gas resources. As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business Our substantial indebtedness could adversely affect our financial health activities or finance future operations or capital needs. and our ability to raise additional capital, and prevent us from fulfilling our obligations under our existing agreements. Similar restrictions could apply to us and our subsidiaries when we refinance or enter into new debt agreements which could intensify the risks described As of December 31, 2013, we had US$317.1 million of total indebtedness above. outstanding on a consolidated basis, of which US$300.1 million, or 94.7%, was secured. As of December 31, 2013, our annual debt service obligation was Our results of operations could be materially adversely affected by approximately US$25.2 million, which includes interest payments under the fluctuations in foreign currency exchange rates. Notes due 2020. See “Item 5. Operating and Financial Review and Prospects— B. Liquidity and Capital Resources—Indebtedness.” Although a majority of our net revenues is denominated in U.S. dollars, Our substantial indebtedness could: unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Chile, Colombia, Brazil and Argentina could have a material • make it more difficult for us to satisfy our obligations with respect to adverse effect on our results of operations. Furthermore, we have not our indebtedness, and any failure to comply with the obligations of any of our entered, and do not anticipate entering, into derivative transactions to debt instruments, including restrictive covenants and borrowing conditions, hedge the effect of changes in the exchange rate of local currencies to the could result in an event of default under the agreements governing our U.S. dollar. Because our consolidated financial statements are presented indebtedness; in U.S. dollars, we must translate revenues, expenses and income, as well as • require us to dedicate a substantial portion of our cash flow from operations assets and liabilities, into U.S. dollars at exchange rates in effect during or to the payments on our indebtedness, thereby reducing the availability of at the end of each reporting period. our cash flow to fund acquisitions, working capital, capital expenditures and other general corporate purposes; In addition, our Rio das Contas acquisition, which closed on March 31, 2014, • place us at a competitive disadvantage compared to certain of our significantly increased our exposure to fluctuations in the real against the competitors that have less debt; • limit our ability to borrow additional funds; 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 • in the case of our secured indebtedness, lose assets securing such to the U.S. dollar and other foreign currencies. For example, the real was indebtedness upon the exercise of security interests in connection with a R$1.56 per US$1.00 in August 2008. Following the onset of the crisis in the default; global financial markets, the real depreciated 31.9% against the U.S. • make us more vulnerable to downturns in our business or the economy; dollar and reached R$2.34 per US$1.00 at the end of 2008. In 2011, the real and appreciated against the U.S. dollar, reaching R$1.876 per US$1.00 at the end • limit our flexibility in planning for, or reacting to, changes in our operations of 2011. In 2012, however, the real depreciated, and on December 31, 2012, or business and the industry in which we operate. the exchange rate was R$2.044 per US$1.00. As of December 31, 2013, the Our Notes due 2020 include a covenant restricting dividend payments. For either depreciation or appreciation of the real could materially and adversely a description, see “Item 5. Operating and Financial Review and Prospects—B. affect the growth of the Brazilian economy and our business, financial Liquidity and Capital Resources—Indebtedness—Notes due 2020.” condition and results of operations. See “—A. Selected financial data— exchange rate was R$2.3426 per US$1.00. Depending on the circumstances, Exchange rates.” 50 GeoPark 20F Risks relating to the countries in which we operate • tax policies; and Our operations may be adversely affected by political and economic of earnings from the countries in which we operate in the future. • the possibility that we may become subject to restrictions on repatriation circumstances in the countries in which we operate and in which we may operate in the future. In addition, our operations in these areas increase our exposure to risks of guerilla activities, social unrest, local economic conditions, political disruption, All of our current operations are located in South America. For the year civil disturbance, community protests or blockades, expropriation, piracy, ended December 31, 2013, our operations in Chile and Colombia represented tribal conflicts and governmental policies that may: disrupt our operations; 51.5% and 48%, respectively, of our total production, with our Argentine require us to incur greater costs for security; restrict the movement of operations representing less than 0.5% of our total production. As of funds or limit repatriation of profits; lead to U.S. government or international December 31, 2013, on a pro forma basis, and accounting for our Rio das sanctions; limit access to markets for periods of time; or influence the Contas acquisition, Chile, Colombia and Brazil represented 41%, 38% and market’s perception of the risk associated with investments in these 21%, respectively, of our average production during the same period. countries. Some countries in the geographic areas where we operate have If local, regional or worldwide economic trends adversely affect the economy experienced, and may experience in the future, political instability, and of any of the countries in which we have investments or operations, our losses caused by these disruptions may not be covered by insurance. financial condition and results from operations could be adversely affected. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse Oil and natural gas exploration, development and production activities are effect on our results of operations and financial condition. subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), Our operations may also be adversely affected by laws and policies of the changes in laws and policies governing operations of foreign-based jurisdictions, including Bermuda, Chile, Colombia, Brazil, Argentina, the companies, expropriation of property, cancellation or modification of contract Netherlands and other jurisdictions in which we do business, that affect rights, revocation of consents or approvals, the obtaining of various foreign trade and taxation, and by uncertainties in the application of, possible approvals from regulators, foreign exchange restrictions, price controls, changes to (or to the application of) tax laws in these jurisdictions. Changes currency fluctuations, royalty increases and other risks arising out of foreign in any of these laws or policies or the implementation thereof, and uncertainty governmental sovereignty, as well as to risks of loss due to civil strife, over potential changes in policy or regulations affecting any of the factors acts of war and community-based actions, such as protests or blockades, mentioned above or other factors in the future may increase the volatility of guerilla activities, terrorism, acts of sabotage, territorial disputes domestic securities markets and securities issued abroad by companies and insurrection. In addition, we are subject both to uncertainties in the operating in these countries, which could materially and adversely affect our application of the tax laws in the countries in which we operate and to financial position, results of operations and cash flows. Furthermore, we may be possible changes in such tax laws (or the application thereof), each of which subject to the exclusive jurisdiction of courts outside the United States or may could result in an increase in our tax liabilities. These risks are higher in developing countries, such as those in which we conduct our activities. not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute. The main economic risks we face and may face in the future because of We depend on maintaining good relations with the respective host our operations in the countries in which we operate include the following: governments and national oil companies in each of our countries of • difficulties incorporating movements in international prices of crude operation. oil and exchange rates into domestic prices; • the possibility that a deterioration in Chile’s, Colombia’s, Argentina’s The success of our business and the effective operation of the fields in each or Brazil’s relations with multilateral credit institutions, such as the IMF, will of our countries of operation depend upon continued good relations and impact negatively on capital controls, and result in a deterioration of the cooperation with applicable governmental authorities and agencies, business climate; including national oil companies such as ENAP and Petrobras. For instance, • inflation, exchange rate movements (including devaluations), exchange for the year ended December 31, 2013, 100% of our crude oil and condensate control policies (including restrictions on remittance of dividends), price sales in Chile were made to ENAP, the Chilean state-owned oil company, instability and fluctuations in interest rates; and 20.9% of our crude oil and condensate sales in Colombia were made • liquidity of domestic capital and lending markets; to Hocol, a subsidiary of Ecopetrol, the Colombian state-owned oil and gas GeoPark 20F 51 company. In addition, our recent Rio das Contas acquisition in Brazil provides legislation or health and safety, this could have a material adverse effect us with a long-term off-take contract with Petrobras, the Brazilian state- on our business, financial condition and results of operations. owned company, that covers approximately 74% of net proved gas reserves in the Manatí Field. If we, the respective host governments and the national Additionally, we are dependent on receipt of Colombian government oil companies are not able to cooperate with one another, it could have approvals or permits to develop the concessions we hold in Colombia. There an adverse impact on our business, operations and prospects. can be no assurance that future political conditions in Colombia will not result in the Colombian government adopting different policies with respect Oil and natural gas companies in Chile, Colombia, Brazil and Argentina to foreign development and ownership of oil, environmental protection, do not own any of the oil and natural gas reserves in such countries. health and safety or labor relations. This may affect our ability to undertake exploration and development activities in respect of present and future Under Chilean, Colombian, Brazilian and Argentine law, all onshore and properties, as well as our ability to raise funds to further such activities. Any offshore hydrocarbon resources in these countries are owned by the delays in receiving Colombian government approvals, permits or no respective sovereign. Although we are the operator of the majority of objection certificates may delay our operations or may affect the status of the blocks and concessions in which we have a working and/or economic our contractual arrangements or our ability to meet contractual obligations. interest and generally have the power to make decisions as how to market the hydrocarbons we produce, the Chilean, Colombian, Brazilian Pursuant to Article 20 of the Brazilian Constitution and Article 3 of Law No. and Argentine governments have full authority to determine the rights, 9,478, dated as of August 6, 1997, as amended, or the Brazilian Petroleum royalties or compensation to be paid by or to private investors for Law, oil, natural gas and hydrocarbon reserves located within the Brazilian the exploration or production of any hydrocarbon reserves located in territory, which encompasses onshore and offshore reserves, as well as their respective countries. deposits in the Brazilian continental shelf, territorial waters and exclusive economic zone, are considered assets of the Brazilian government. Therefore, Under the Chilean Constitution, the state is the exclusive owner of all mineral the concessionaire owns only the oil and natural gas that it produces under and fossil substances, including hydrocarbons, regardless of who owns the the concession agreements. Oil and natural gas companies in Brazil acquire land on which the reserves are located. The exploration and exploitation the exclusive right to explore, develop and produce reserves discovered of hydrocarbons may be carried out by the state, companies owned by state within certain concession areas pursuant to concession agreements awarded or private persons through administrative concessions granted by the by the Brazilian government. However, if the Brazilian government were to President of Chile by Supreme Decree or by CEOPs executed by the Minister restrict or prevent concessionaires, including us, from exploiting these oil and of Energy. Hydrocarbon exploration and exploitation activities are regulated natural gas reserves, or interfere in the sale or transfer of the production, by the Chilean Ministry of Energy. In Chile, a participant is granted rights to our ability to generate income would be materially adversely affected, which explore and exploit certain assets under a CEOP. Although the government would have a material adverse effect on our business, financial condition cannot unilaterally modify or terminate the rights granted in the CEOP once and results of operations. it is signed, if a participant fails to complete certain obligations under a CEOP, such participant may lose the right to exploit certain areas or may be Companies in the Brazilian oil and natural gas industry also rely primarily required to return all or a portion of the awarded areas back to Chile. on the public auction process regulated by the ANP to acquire rights to In Colombia, oil and natural gas companies have acquired the exclusive certain basins in future bidding rounds, there is a risk that future bidding right to explore, develop and produce reserves discovered within certain rounds may not take place or that they do not include desirable locations, concession areas, pursuant to concession agreements awarded by the since they are conducted by and under the Brazilian government’s discretion, Colombian government through the ANH or, prior to 2004, entered into with which could have a material adverse effect on our business, expected results explore oil and natural gas reserves. While the ANP may offer concessions in Ecopetrol. However, a concessionaire owns only the oil and natural gas that of operations and financial condition. it extracts under the concession agreements to which it is a party. If the Colombian government were to restrict or prevent concessionaires, including In Argentina, jurisdiction over oil and gas activities is now largely vested us, from exploiting these oil and natural gas reserves, or otherwise interfere in the same provincial states who own the relevant underground oil and gas with our exploration through regulations with respect to restrictions on resources. The Federal Executive Branch is still empowered to design future exploration and production, price controls, export controls, foreign and rule federal energy policy and to rule on domestic inter-jurisdictional exchange controls, income taxes, expropriation of property, environmental and international oil and gas transportation concessions and has, for example, 52 GeoPark 20F imposed measures controlling oil and gas investments in the provincial expenditures and required divestments. Existing Colombian regulation states. Private companies must obtain exploration permits or exploitation applies to virtually all aspects of our concessions or E&P Contracts in Colombia. concessions from the provincial states or otherwise enter into certain types The terms and conditions of the agreements with the ANH generally reflect of joint venture or association agreements with provincial state-owned negotiations with the ANH and other Colombian governmental authorities, oil and gas companies in order to undertake exploration and production and may vary by fields, basins and hydrocarbons discovered. activities onshore, and must enter into certain types of joint venture or association agreements with the federally-owned oil and gas company, We are required, as are all oil companies undertaking exploratory and ENARSA, to undertake these activities offshore. Additionally, whereas until production activities in Colombia, to pay a percentage of our expected 2012, exploration permit and exploitation concession holders had the production to the Colombian government as royalties. The Colombian right to freely dispose of and market up to 70% of the production they government has modified the royalty program for oil and natural gas generated, on July 28th, 2012, the publication of Presidential Decree production several times in the last 20 years, as it has modified the regime 1277/2012 abrogated this right. As of December 31, 2013, our production regulating new contracts entered into with the Colombian government. in Argentina represented less than 0.5% of our total production, though The royalty regime for contracts being entered into today for conventional recent regulations affecting the oil and gas industry in Argentina may have oil is tied to a scale ring-fenced by field starting at 8% for production an adverse impact on our business, operations and prospects in Argentina. of up to 5,000 mbopd and increases up to 25% for production above Oil and gas operators are subject to extensive regulation in the countries our assets are located, range between 8% and 25%. Furthermore, production 600,000 mbopd. Royalties for natural gas production of onshore blocks where in which we operate. of unconventional resources discovered as of May 19, 2012 is subject to royalties equivalent to 60% of the royalties applicable to conventional oil. In Chile, rights to exploration and exploitation of a particular area are established in a CEOP. According to article 19, No 24 of the Chilean In Brazil, the oil and natural gas industry is subject to extensive regulation Constitution, the President of Chile has the power to determine the terms and intervention by the Brazilian government in such matters as the and conditions for the granting of a particular CEOP. In addition, the CEOP award of exploration and production interests, taxation and foreign currency is subject to extensive supervision by the government through the Chilean controls. Ultimately, those regulations may also address restrictions on Ministry of Energy. The President of Chile may also decide to terminate production, price controls, mandatory divestments of assets and a CEOP early, though with compensation to the counterparty, and only nationalization, expropriation or cancellation of contractual rights. if the relevant area is located within an area declared relevant for national security reasons. Under these laws and regulations, there is potential liability for personal injury, property damage and other types of damages. Failure to comply Although the government of Chile cannot unilaterally modify the rights with these laws and regulations also may result in the suspension or granted in the CEOP once it is signed, exploration and exploitation are termination of operations or our being subjected to administrative, civil nonetheless subject to significant government regulations, such as regulations concerning the environment, tort liability, health and safety and and criminal penalties, which could have a material adverse effect on our financial condition and expected results of operations. We expect to labor, all of which have an impact on our business and operations. Changes also operate in a consortium in some of our concessions, which, under in laws and regulations could have an adverse effect on the costs and timing the Brazilian Petroleum Law, establishes joint and strict liability among of our operations. For example, in November 2012, the government consortium members. If the operator does not maintain the appropriate approved new regulations governing the abandonment of oilfield operations licenses, the consortium may suffer administrative penalties, including that would require us to obtain prior approval for new oil wells and could fines of R$10 to R$500 million. also require us to post a bond in connection with the abandonment or closure of an oil well. In addition, the local content policy, which is a contractual requirement in a Brazilian concession agreements, has become a significant issue for oil The Colombian hydrocarbons industry is subject to extensive regulation and natural gas companies operating in Brazil given the penalties related and supervision by the government in matters such as the environment, with breaches thereof. The local content requirement will also apply to the tort liability, health and safety, labor, the award of exploration and production production sharing contract regime. See “Item 4. Information on the contracts by the ANH, the imposition of specific drilling and exploration Company—B. Business overview—Brazil.” obligations, taxation, foreign currency controls, price controls, capital GeoPark 20F 53 The Argentine hydrocarbons industry is also extensively regulated both by In Argentina, since 2001, the Argentine government has imposed and federal and provincial state regulations in matters including the award expanded upon exchange controls and restrictions on the transfer of exploration permits and exploitation concessions, investment, royalty, of U.S. dollars outside of Argentina, which substantially limit the ability canon, price controls, export restrictions and domestic market supply of companies to retain foreign currency or make payments abroad. obligations. The terms of our exploitation concessions are embodied in These and other measures have led the implied AR$/US$ exchange rate as Decrees and Administrative Decisions issued by the Federal Executive reflected in the quotations for certain Argentine securities that trade in Power and incorporate statutory rights and obligations provided under the foreign markets to differ substantially from the official foreign exchange rate Hydrocarbons Law. The federal government is further empowered to in Argentina. If the Argentine government decides once again to tighten design and implement federal energy policy and to rule on domestic inter- the restrictions on the transfer of funds, we may be unable to make payments jurisdictional and international oil and gas transportation concessions, related to the import of products and services, which could have a material and has used these powers to establish export restrictions and duties, adverse effect on us. induce private companies to enter into price stability agreements with the government or otherwise impose price control regulations or create incentive Additionally, in May 2012, the Argentine government expropriated 51% programs to promote increased production. Jurisdictional controversies of YPF’s capital stock owned by Repsol YPF of Spain, and 51% of the capital among the federal government and the provincial states are not uncommon. stock of Repsol YPF Gas owned by Repsol Butano. Significant expenditures may be required to ensure our compliance with There can be no assurance that future economic, social and political governmental regulations related to, among other things, licenses for developments in the countries in which we operate currently or in the future, drilling operations, environmental matters, drilling bonds, reports concerning which are out of our control, may impair our business, financial condition operations, the spacing of wells, unitization of oil and natural gas and results of operations. accumulations, local content policy and taxation. Governmental actions in the countries in which we operate and in which we operate and in which we may operate in the future. Our operations may be affected by tax reforms in the countries in which we may operate in the future may adversely affect our business, financial condition and results of operations. 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. For example, Our business, financial condition and results of operations may be adversely in early April 2014, the Chilean government put forth a proposal for an affected by actions taken by the Chilean, Colombian, Brazilian or Argentine income tax-reform which is designed to increase government revenues. The governments concerning the economy, including actions aimed at targeting proposed tax reform eliminates certain tax structures that were previously inflation, interest rates, oil and gas price controls, foreign exchange controls beneficial to large companies, including deferral of taxes paid on reinvested and taxes. Brazil has in the past periodically experienced extremely high rates of company profits. Although, as of the date of this annual report, we cannot estimate the full impact of these proposed tax reforms on our Chilean operations, there can be no assurance that these tax reforms will not be inflation. As measured by the National Consumer Price Index ( Índice Nacional implemented and have an adverse impact on our cash flow and profitability de Preços ao Consumidor Amplo ), Brazil had annual rates of inflation of 5.9% due to the loss of certain advantageous tax structures. in 2010, 6.5% in 2011, 5.8% in 2012 and 5.9% in 2013. Brazil may experience high levels of inflation in the future. Periods of higher inflation may slow In Brazil, the Brazilian government frequently implements changes to tax and the rate of growth of the Brazilian economy. Although the long-term off-take social security regimes that may affect us and our customers. These changes contract covering gas production in the Manatí Field is indexed to inflation, include changes in prevailing tax and contribution rates and, occasionally, inflation is likely to increase some of our costs and expenses, and, as a result, enactment of temporary taxes, the proceeds of which are earmarked for may reduce our profit margins and net income. Inflationary pressures could designated governmental purposes. Some of these changes in tax laws may also lead to counter-inflationary prices that may harm our business. Any result in increases in our tax payments, which could materially adversely decline in our expected net sales or net income could lead to a deterioration affect our profitability and increase the prices of our products and services, in our financial condition. restrict our ability to do business in our existing and target markets and cause our results of operations to suffer. There can be no assurance that we will be 54 GeoPark 20F able to maintain our projected cash flow and profitability following any adversely affected. In particular, we face risks in Argentina related to increase in taxes applicable to us and to our operations. the following: restrictions on Argentina’s energy supplies and an inadequate governmental response to such restrictions, which could negatively affect Colombia has experienced and continues to experience internal security Argentina’s economic activity; social and political tensions and the issues that have had or could have a negative effect on the Colombian governmental response to such tensions; requirements of the Federal economy. General Environmental Law, which requires persons who carry out activities that are potentially hazardous to the environment to obtain insurance; Colombia has experienced internal security issues, primarily due to the and tax implications under Argentine law with respect to our incorporation activities of guerrillas, including the Revolutionary Armed Forces of in Bermuda, which may subject our Argentine subsidiaries to higher tax rates. Colombia ( Fuerzas Armadas Revolucionarias de Colombia ), or the FARC, paramilitary groups and drug cartels. In the past, guerrillas have targeted Risks related to our common shares the crude oil pipelines, including the Oleoducto Transandino, Caño Limón-Coveñas and Ocensa pipelines, and other related infrastructure An active, liquid and orderly trading market for our common shares may disrupting the activities of certain oil and natural gas companies. On several not develop and the price of our stock may be volatile, which could limit occasions guerilla attacks have resulted in unscheduled shut-downs of your ability to sell our common shares. the transportation systems in order to repair damaged sections and undertake clean-up activities. These activities, their possible escalation and Our common shares began to trade on the New York Stock Exchange the effects associated with them have had and may have in the future a on February 7, 2014, and as a result have a limited trading history. We cannot negative impact on the Colombian economy or on our business, which may predict the extent to which investor interest in our company will maintain affect our employees or assets. In the context of the political instability, an active trading market on the NYSE, or how liquid that market will be allegations have been made against members of the Colombian Congress in the future. and against government officials for possible ties with guerilla groups. This situation may have a negative impact on the credibility of the The market price of our common shares may be volatile and may be Colombian government, which could in turn have a negative impact on influenced by many factors, some of which are beyond our control, including: the Colombian economy or on our business in the future. • our operating and financial performance and identified potential drilling locations, including reserve estimates; The Colombian government commenced peace talks with the FARC in • quarterly variations in the rate of growth of our financial indicators, such as August 2012. Our business, financial condition and results of operations net income per common share, net income and revenues; could be adversely affected by rapidly changing economic or social • changes in revenue or earnings estimates or publication of reports by conditions, including the Colombian government’s response to current equity research analysts; peace negotiations which may result in legislation that increases our tax • speculation in the press or investment community; burden or that of other Colombian companies. Tensions with neighboring countries may affect the Colombian economy and, consequently, our • sales of our common shares by us or our shareholders, or the perception that such sales may occur; results of operations and financial condition. • involvement in litigation; • changes in personnel; In addition, from time to time, community protests and blockades may arise • announcements by the company; near our operations in Colombia, which could adversely affect our business, • domestic and international economic, legal and regulatory factors unrelated financial condition or results of operations. to our performance. Our operations may be adversely affected by political and economic • volatility in our industry, the industries of our customers and the global circumstances in Argentina. securities markets; • changes in our dividend policy; Some of our current operations and management offices are located in • risks relating to our business and industry, including those discussed above; Argentina. If local political or economic trends adversely affect the Argentine • strategic actions by us or our competitors; economy, our financial condition and results from operations could be • variations in our quarterly operating results; GeoPark 20F 55 • actual or expected changes in our growth rates or our competitors’ in the form of loans, dividends, distributions or otherwise. The ability of our growth rates; subsidiaries to distribute cash to us is also subject to, among other things, • investor perception of us, the industry in which we operate, the investment restrictions that are contained in our and our subsidiaries’ financing opportunity associated with our common shares and our future performance; (including our Notes due 2020 and GeoPark Brazil’s loan to finance Rio das • adverse media reports about us or our directors and officers; Contas) and joint venture agreements (principally our agreements with LGI), • addition or departure of our executive officers; availability of sufficient funds in such subsidiaries and applicable state laws • change in coverage of our company by securities analysts; and regulatory restrictions. Claims of creditors of our subsidiaries generally • trading volume of our common shares; will have priority as to the assets of such subsidiaries over our claims and • future issuances of our common shares or other securities; claims of our creditors and stockholders. To the extent the ability of our • terrorist acts; subsidiaries to distribute dividends or other payments to us could be limited • the release or expiration of lock-up or other transfer restrictions on our in any way, our business, financial condition and results of operations, as well outstanding common shares. as our ability to pay dividends on the common shares, could be materially adversely affected. We have never declared or paid, and do not intend to pay in the foreseeable future, cash dividends on our common shares, and, consequently, your Additionally, we may not be able to fully control the operations and the only opportunity to achieve a return on your investment is if the price of our assets of our joint ventures and we may not be able to make major stock appreciates. decisions or take timely actions with respect to our joint ventures unless our joint venture partners agree. For example, we have entered into We have never paid, and do not intend to pay in the foreseeable future, cash shareholder agreements with LGI in Chile and Colombia that limit the amount dividends on our common shares. Any decision to pay dividends in the of dividends that can be declared or returned to us, certain aspects related future, and the amount of any distributions, is at the discretion of our board to the management of our Chilean and Colombian businesses, the incurrence of directors and our shareholders, and will depend on many factors, such of indebtedness, liens and our ability to sell certain assets. See “—Risks as our results of operations, financial condition, cash requirements, prospects relating to our business—LGI, our strategic partner in Chile and Colombia, and other factors. may sell its interest in our Chilean and Colombian operations to a third party or may not consent to our taking certain actions.” We may, in the future, We are also subject to Bermuda legal constraints that may affect our ability enter into other joint venture agreements imposing additional restrictions to pay dividends on our common shares and make other payments. Under on our ability to pay dividends. the Bermuda Companies Act, we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment Sales of substantial amounts of our common shares in the public market, be, unable to pay our liabilities as they become due or that the realizable or the perception that these sales may occur, could cause the market value of our assets would thereafter be less than our liabilities. We are also price of our common shares to decline. subject to contractual restrictions under certain of our indebtedness. We are a holding company dependent upon dividends from our future, for example, to finance potential acquisitions of assets, which we subsidiaries, which may be limited by law and by contract from making intend to continue to pursue. Sales of substantial amounts of our common distributions to us, which would affect our ability to pay dividends shares in the public market, or the perception that these sales may occur, We may issue additional common shares or convertible securities in the on the common shares. could cause the market price of our common shares to decline. This could also impair our ability to raise additional capital through the sale of our As a holding company, our only material assets are our cash on hand, the equity securities. Under our memorandum of association, we are authorized equity interests in our subsidiaries and other investments. Our principal to issue up to 5,171,949,000 common shares, of which 57,863,615 common source of revenues and cash flow is distributions from our subsidiaries. Thus, shares were outstanding as of the date of this annual report. We cannot our ability to pay dividends on the common shares will be contingent upon predict the size of future issuances of our common shares or the effect, the financial condition of our subsidiaries. Our subsidiaries are and will be if any, that future sales and issuances of shares would have on the market separate legal entities, and although they may be wholly-owned or controlled price of our common shares. by us, they have no obligation to make any funds available to us, whether 56 GeoPark 20F Provisions of the Notes due 2020 could discourage an acquisition of us Securities Exchange Act of 1934, as amended, or the Exchange Act. Although by a third party. we intend to report quarterly financial results and report certain material events, we are not required to file quarterly reports on Form 10-Q or provide Certain provisions of the Notes due 2020 could make it more difficult current reports on Form 8 K disclosing significant events within four days or more expensive for a third party to acquire us, or may even prevent a of their occurrence and our quarterly or current reports may contain less third party from acquiring us. For example, upon the occurrence of a information than required under U.S. filings. In addition, we are exempt from fundamental change, holders of the Notes due 2020 will have the right, the Section 14 proxy rules, and proxy statements that we distribute will at their option, to require us to repurchase all of their notes at a purchase not be subject to review by the SEC. Our exemption from Section 16 rules price equal to 101% of the principal amount thereof plus any accrued regarding sales of common shares by insiders means that you will have less and unpaid interest (including any additional amounts, if any) to the date data in this regard than shareholders of U.S. companies that are subject of purchase. By discouraging an acquisition of us by a third party, these to the Exchange Act. As a result, you may not have all the data that you are provisions could have the effect of depriving the holders of our common accustomed to having when making investment decisions. For example, our shares of an opportunity to sell their common shares at a premium over officers, directors and principal shareholders are exempt from the reporting prevailing market prices. and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules thereunder with respect to their purchases and sales Certain shareholders have substantial control over us and could limit of our common shares. The periodic disclosure required of foreign private your ability to influence the outcome of key transactions, including issuers is more limited than that required of domestic U.S. issuers and there a change of control. may therefore be less publicly available information about us than is regularly published by or about U.S. public companies. See “Item 10. Additional Mr. Gerald E. O’Shaughnessy, our Chairman, Mr. James F. Park, our Chief Information—H. Documents on display.” Executive Officer, Mr. Juan Cristóbal Pavez, a director and Mr. Steven J. Quamme, a director, control approximately 48% of our outstanding common As a foreign private issuer, we will be exempt from complying with certain shares as of the date of this annual report, holding the shares either directly corporate governance requirements of the NYSE applicable to a U.S. issuer, or through privately held funds which they control. As a result, these including the requirement that a majority of our board of directors consist of shareholders, if acting together, would be able to influence or control matters independent directors. As the corporate governance standards applicable requiring approval by our shareholders, including the election of directors to us are different than those applicable to domestic U.S. issuers, you may not and the approval of amalgamations, mergers or other extraordinary have the same protections afforded under U.S. law and the NYSE rules as transactions. They may also have interests that differ from yours and may shareholders of companies that do not have such exemptions. vote in a way with which you disagree and which may be adverse to your interests. The concentration of ownership may have the effect of We are an “emerging growth company,” and we cannot be certain if the delaying, preventing or deterring a change of control of our company, could reduced disclosure requirements applicable to emerging growth companies 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 will make our common shares less attractive to investors. the market price of our common shares. See “Item 7. Major Shareholders We are an “emerging growth company,” as defined in the JOBS Act, and for and Related Party Transactions—A. Major shareholders” for a more detailed as long as we continue to be an “emerging growth company” we may choose description of our share ownership to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth As a foreign private issuer, we are subject to different U.S. securities laws companies,” including, but not limited to, not being required to comply and NYSE governance standards than domestic U.S. issuers. This may with the auditor attestation requirements of Section 404(b) of the Sarbanes afford less protection to holders of our common shares, and you may not Oxley Act. We cannot predict if investors will find our common shares less receive corporate and company information and disclosure that you attractive because we will rely on these exemptions. If some investors find our are accustomed to receiving or in a manner in which you are accustomed common shares less attractive as a result, there may be a less active trading to receiving it. market for our common shares and our share price may be more volatile. As a foreign private issuer, the rules governing the information that we Under the JOBS Act, emerging growth companies can delay adopting new disclose differ from those governing U.S. corporations pursuant to the or revised accounting standards until such time as those standards apply GeoPark 20F 57 to private companies. We have irrevocably elected not to avail ourselves of We will continue to incur significantly increased costs and devote this exemption from new or revised accounting standards, and, therefore, substantial management time as a result of operating as a public company. we will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies. Our recent initial public offering will have a significant transformative effect Our internal controls over financial reporting may not be effective which expenses as a result of having publicly traded common shares listed on could have a significant and adverse effect on our business and reputation. the NYSE. We will also incur costs which we have not incurred previously, We intend to evaluate our internal controls over financial reporting in directors and officers insurance, investor relations, and various other costs including, but not limited to, costs and expenses for directors’ fees, increased on us. We expect to incur significant legal, accounting, reporting and other order to allow management to report on, our internal controls over financial of a public company. reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, as amended, and rules and regulations of the United States Securities and We also anticipate that we will incur costs associated with corporate Exchange Commission (the “SEC”) thereunder, which we refer to as “Section governance requirements, including requirements under the Sarbanes Oxley 404.” The process of documenting and testing our internal control Act of 2002, as well as rules implemented by the SEC and NYSE. We expect procedures in order to satisfy the requirements of Section 404 requires these rules and regulations to increase our legal and financial compliance annual management assessments of the effectiveness of our internal controls costs and make some management and corporate governance activities more over financial reporting. During the course of our internal testing, we may time-consuming and costly, particularly after we are no longer an “emerging identify deficiencies of which we are not currently aware. growth company.” These rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance, In addition, if we fail to achieve and maintain the adequacy of our internal and we may be required to accept reduced policy limits and coverage or incur controls, as such standards are modified, supplemented or amended from substantially higher costs to obtain the same or similar coverage. This could time to time, we may not be able to ensure that we can conclude on an have an adverse impact on our ability to recruit and bring on a qualified ongoing basis that we have effective internal controls over financial reporting independent board. in accordance with Section 404. We are not currently required to furnish a report on our internal control over financial reporting and we expect that this The additional demands associated with being a public company listed rule will apply to us when we file our annual report on Form 20-F for our on the NYSE may disrupt regular operations of our business by diverting the fiscal year ending December 31, 2014, which we will be required to file by attention of some of our senior management team away from revenue- April 30, 2015. In addition, we are not currently required to include an producing activities to management and administrative oversight, adversely attestation report of our auditors on our assessment of internal controls over affecting our ability to attract and complete business opportunities and financial reporting pursuant to the SEC’s rules under Section 404, for as increasing the difficulty in both retaining professionals and managing and long as we continue to be an “emerging growth company”. We cannot be growing our businesses. Any of these effects could harm our business, certain as to the timing of completion of our evaluation, testing and any remediation actions or the impact of the same on our operations. If we are financial condition and results of operations. not able to implement the requirements of Section 404 in a timely manner There are regulatory limitations on the ownership and transfer of our or with adequate compliance, we may not be able to certify as to the common shares which could result in the delay or denial of any transfers effectiveness of our internal controls over financial reporting and we may you might seek to make. be subject to sanctions, stock exchange delisting or investigation by regulatory authorities, such as the SEC. The Bermuda Monetary Authority, or the BMA, must specifically approve all issuances and transfers of securities of a Bermuda exempted company like As a result, there could be a negative reaction in the financial markets due us unless it has granted a general permission. We are able to rely on a general to a loss of confidence in the reliability of our financial statements. This permission from the BMA to issue our common shares, and to freely transfer could harm our reputation and may otherwise negatively affect our financial of our common shares as long as the common shares are listed on the NYSE condition, results of operations and cash flows. In addition, we may be and/or other appointed stock exchange, to and among persons who are required to incur costs in improving our internal control system and the hiring non-residents of Bermuda for exchange control purposes. Any other transfers of additional personnel. remain subject to approval by the BMA and such approval may be denied or delayed. 58 GeoPark 20F We are a Bermuda company, and it may be difficult for you to enforce United States. As a Bermuda company, we are governed by our memorandum judgments against us or against our directors and executive officers. of association and bye-laws and Bermuda company law. The provisions of the Bermuda Companies Act, which applies to us, differs in some material We are incorporated as an exempted company under the laws of Bermuda respects from laws generally applicable to U.S. corporations and shareholders, and substantially all of our assets are located in Chile, Colombia, Argentina including the provisions relating to interested directors, mergers and and Brazil. In addition, most of our directors and executive officers reside acquisitions, takeovers, shareholder lawsuits and indemnification of directors. outside the United States and all or a substantial portion of the assets of such Set forth below is a summary of these provisions, as well as modifications persons are located outside the United States. As a result, it may be difficult adopted pursuant to our bye-laws, which differ in certain respects or impossible to effect service of process within the United States upon us, or from provisions of Delaware corporate law. Our shareholders approved the to recover against us on judgments of U.S. courts, including judgments adoption of new bye-laws which came into effect on February 19, 2014, being predicated upon the civil liability provisions of the U.S. federal securities laws. the date on which the company cancelled admission of its common shares Further, no claim may be brought in Bermuda against us or our directors on AIM. Because the following statements are summaries, they do not discuss and officers in the first instance for violation of U.S. federal securities laws all aspects of Bermuda law that may be relevant to us and our shareholders. because these laws have no extraterritorial application under Bermuda law and do not have force of law in Bermuda. However, a Bermuda court may Interested Directors. Under our bye-laws and The Companies Act, 1981(as impose civil liability, including the possibility of monetary damages, on us or amended) of Bermuda, or the Bermuda Companies Act, a director shall our directors and officers if the facts alleged in a complaint constitute or declare the nature of his interest in any contract or arrangement with the give rise to a cause of action under Bermuda law. 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 There is no treaty in force between the United States and Bermuda providing quorum at a meeting in relation to any resolution in which he has an interest, for the reciprocal recognition and enforcement of judgments in civil and which is to his knowledge, a material interest (otherwise than by virtue commercial matters. As a result, whether a United States judgment would be of his interest in shares or debentures or other securities of or otherwise in enforceable in Bermuda against us or our directors and officers depends or through the company). In addition, the director will not be liable to us on whether the U.S. court that entered the judgment is recognized by the for any profit realized from the transaction. In contrast, under Delaware law, Bermuda court as having jurisdiction over us or our directors and officers, such a contract or arrangement is voidable unless it is approved by a majority as determined by reference to Bermuda conflict of law rules. A judgment of disinterested directors or by a vote of shareholders, in each case if the debt from a U.S. court that is final and for a sum certain based on U.S. federal material facts as to the interested director’s relationship or interests are securities laws will not be enforceable in Bermuda unless the judgment disclosed or are known to the disinterested directors or shareholders, or such debtor had submitted to the jurisdiction of the U.S. court, and the issue of contract or arrangement is fair to the corporation as of the time it is approved submission and jurisdiction is a matter of Bermuda (not U.S.) law. or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit. In addition, and irrespective of jurisdictional issues, the Bermuda courts will not enforce a U.S. federal securities law that is either penal or contrary to Amalgamations, Mergers and Similar Arrangements. Pursuant to the Bermuda Bermuda public policy. An action brought pursuant to a public or penal law, Companies Act, the amalgamation or merger of a Bermuda company with the purpose of which is the enforcement of a sanction, power or right at another company or corporation requires the amalgamation or merger the instance of the state in its sovereign capacity, will not be entertained by a agreement to be approved by the company’s board of directors and by Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, its shareholders. Shareholder approval is not required where (i) the holding including certain remedies under U.S. federal securities laws, would not be company and one or more of its wholly-owned subsidiary companies available under Bermuda law or enforceable in a Bermuda court, as they amalgamate or merge or (ii) two or more wholly-owned subsidiary companies would be contrary to Bermuda public policy. of the same holding company amalgamate or merge. Save for such “short- Bermuda law differs from the laws in effect in the United States and might otherwise, the approval of 75% of the shareholders voting at such meeting form” amalgamations or mergers, unless the company’s bye-laws provide afford less protection to shareholders. is required to approve the amalgamation or merger agreement, and the quorum for such meeting must be two persons holding or representing more Our shareholders could have more difficulty protecting their interests than than one-third of the issued shares of the company. Under our bye-laws, would shareholders of a corporation incorporated in a jurisdiction of the an amalgamation or merger will require the approval of our board of directors GeoPark 20F 59 and of our shareholders by Special Resolution, meaning a resolution adopted applicable law. In such actions, the court has discretion to permit the winning by 65% of more of the votes cast by shareholders who (being entitled to do party to recover attorneys’ fees incurred in connection with such action. so) vote in person or by proxy at any general meeting of the shareholders iin accordance with the provisions of the bye-laws. Under Bermuda law, in the Indemnification of Directors. We may indemnify our directors and officers in event of an amalgamation or merger of a Bermuda company with another their capacity as directors or officers for any loss arising or liability attaching company or corporation, a shareholder of the Bermuda company who is to them by virtue of any rule of law in respect of any negligence, default, not satisfied that fair value has been offered for such shareholder’s shares breach of duty or breach of trust of which a director or officer may be guilty may, within one month of notice of the shareholders meeting, apply to in relation to the company other than in respect of his own fraud or the Supreme Court of Bermuda to appraise the fair value of those shares. dishonesty. Our bye-laws provide that we shall indemnify our officers and Under Delaware law, with certain exceptions, a merger, consolidation or sale directors in respect of their acts and omissions, except in respect of their of all or substantially all the assets of a corporation must be approved by fraud or dishonesty, or to recover any gain, personal profit or advantage to the board of directors and a majority of the issued and outstanding shares which such Director is not legally entitled, and (by incorporation of the entitled to vote thereon. Under Delaware law, a shareholder of a corporation provisions of the Bermuda Companies Act) that we may advance moneys to participating in certain major corporate transactions may, under certain our officers and directors for the costs, charges and expenses incurred by our circumstances, be entitled to appraisal rights pursuant to which such officers and directors in defending any civil or criminal proceedings against shareholder may receive cash in the amount of the fair value of the shares them on condition that the directors and officers repay the moneys if any held by such shareholder (as determined by a court) in lieu of the allegations of fraud or dishonesty is proved against them provided, however, consideration such shareholder would otherwise receive in the transaction. that, if the Bermuda Companies Act requires, and advancement of expenses shall be made only upon delivery to the Company of an undertaking, by Shareholders’ Suit. Class actions and derivative actions are generally not or on behalf of such indemnitee, to repay all amounts if it shall ultimately be available to shareholders under Bermuda law. The Bermuda courts, however, determined by final decision that such indemnitee is not entitled to be would ordinarily be expected to permit a shareholder to commence an indemnified for such expenses under our Bye-law. Under Delaware law, a action in the name of a company to remedy a wrong to the company where corporation may indemnify a director or officer of the corporation against the act complained of is alleged to be beyond the corporate power of expenses (including attorneys’ fees), judgments, fines and amounts paid the company or illegal, or would result in the violation of the company’s in settlement actually and reasonably incurred in defense of an action, suit or memorandum of association or bye-laws. Furthermore, consideration would proceeding by reason of such position if such director or officer acted in good be given by a Bermuda court to acts that are alleged to constitute a fraud faith and in a manner he or she reasonably believed to be in or not opposed against the minority shareholders or where an act requires the approval to the best interests of the corporation and, with respect to any criminal of a greater percentage of the company’s shareholders than that which action or proceeding, such director or officer had no reasonable cause to actually approved it. believe his or her conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, As a result of these differences, investors could have more difficulty one or more shareholders may apply under the Bermuda Companies Act protecting their interests than would shareholders of a corporation for an order of the Supreme Court of Bermuda, which may make such order incorporated in the United States. 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 We may become subject to taxes in Bermuda after March 31, 2035, by other shareholders or by the company. which may have a material adverse effect on our results of operations. Our bye-laws contain a provision by virtue of which we and our shareholders Under current Bermuda law, we are not subject to tax on income or capital waive any claim or right of action that they have, both individually and on our gains. We have received from the Minister of Finance under The Exempted behalf, against any director or officer in relation to any action or failure to take Undertaking Tax Protection Act 1966, as amended, an assurance that, in action by such director or officer, except in respect of any fraud or dishonesty the event that Bermuda enacts legislation imposing tax computed on profits, of such director or officer. Class actions and derivative actions generally are income, any capital asset, gain or appreciation, or any tax in the nature of available to shareholders under Delaware law for, among other things, breach estate duty or inheritance, then the imposition of any such tax shall not of fiduciary duty, corporate waste and actions not taken in accordance with be applicable to us or to any of our operations or shares, debentures or other 60 GeoPark 20F obligations, until March 31, 2035. We could be subject to taxes in Bermuda ITEM 4. INFORMATION ON THE COMPANY after that date. This assurance is subject to the provision that it is not to be construed to prevent the application of any tax or duty to such persons A. History and development of the company as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967 or otherwise payable in relation to any property leased to us. We are General We were incorporated as an exempted company pursuant to the laws of incorporated in Bermuda as an exempted company and pay annual Bermuda Bermuda as GeoPark Holdings Limited in February 2006. On July 30, 2013, our government fees. In addition, all entities employing individuals in Bermuda shareholders approved a change in our name to GeoPark Limited, effective are required to pay a payroll tax and there are other sundry taxes payable, from July 31, 2013. We maintain a registered office in Bermuda at Cumberland directly or indirectly, to the Bermuda government. Neither we nor our House, 9th Floor, 1 Victoria Street, Hamilton HM 11, Bermuda. Our principal Bermuda subsidiaries employ individuals in Bermuda as at the date of this executive offices are located at Nuestra Señora de los Ángeles 179, Las annual report. Condes, Santiago, Chile, telephone number +562 2242 9600, and Florida 981, 1st floor, Buenos Aires, Argentina, telephone number +5411 4312 9400. Our The transfer of our common shares may be subject to capital gains taxes website is www.geo-park.com. The information on our website does not pursuant to indirect transfer rules in Chile. constitute part of this annual report. In September 2012, Chile established “indirect transfer rules,” which impose taxes, under certain circumstances, on capital gains resulting from indirect Our company We are an independent oil and natural gas exploration and production, or transfers of shares, equity rights, interests or other rights in the equity, E&P, company with operations in Latin America and a proven track record of control or profits of a Chilean entity, as well as on transfers of other assets growth in production, reserves and cash flows since 2006. We operate in and property of permanent establishments or other businesses in Chile, or Chile, Colombia, Brazil and, to a lesser extent, in Argentina, and also in 2014 the Chilean Assets. As we indirectly own Chilean Assets, the indirect transfer further expanded our footprint in Brazil as a result of our Rio das Contas rules would apply to transfers of our common shares provided certain acquisition, which closed on March 31, 2014. See “B. Business Overview— conditions outside of our control are met. If such conditions were present Our operations—Operations in Brazil.” and as a result the indirect transfer rules were to apply to sales of our common shares, such sales would be subject to indirect transfer tax on the We have a well-balanced portfolio of assets that includes working and/or capital gain that may be determined in each transaction. For a description of economic interests in 27 hydrocarbons blocks, 26 of which are onshore the indirect transfer rules and the conditions of their application see “Item 10. blocks, including eleven currently in production, as well as in an additional Additional Information—E. Taxation—Chilean tax on transfers of shares.” shallow- offshore concession in Brazil that includes the Manatí Field. In addition, we have two new concessions in Brazil that are subject to Our common shares will for a time trade on two separate stock markets, confirmation of qualification requirements by the ANP. We produced a net and investors seeking to take advantage of price differences between such markets may create unexpected volatility in our share price; in addition, average of 13,517 boepd during the year ended December 31, 2013, 51.5% of which was produced in Chile, 48% of which was produced in Colombia investors may not be able to easily move common shares for trading and 0.5% of which was produced in Argentina, and of which 82% was oil. between such markets. As of December 31, 2013, we had net proved reserves of 20.1 mmboe (composed of 74% oil and 26% natural gas), of which 10.7 mmboe, or 53%, Our common shares are currently registered on the NYSE and the Santiago and 9.4 mmboe, or 47%, were in Chile and Colombia, respectively. After Offshore Stock Exchange. Although we intend to de-register from the giving effect to the Rio das Contas acquisition on a pro forma basis, we Santiago Offshore Stock Exchange as soon as practicable, our common would have produced an average of 17,098 boepd during the year ended shares will be traded on two markets for a period of time. During such time, December 31, 2013, with Chile, Colombia and Brazil representing 41%, 38% price levels for our common shares could fluctuate between markets, and 21% of our production, respectively, and with oil representing 65% independent of our share price on the other market. Investors could seek to of our total production. Additionally, according to the D&M Reserves Report, sell or buy our common shares to take advantage of any price differences as of December 31, 2013, Rio das Contas had net proved reserves of between the markets through a practice referred to as arbitrage. Any 8.3 mmboe (composed of approximately 98% natural gas). arbitrage activity could create unexpected volatility in the price of our common shares on the NYSE. GeoPark 20F 61 We have built our company around three principal capabilities: Brazil, which produced approximately 7.6% of the gas produced in Brazil • as an Explorer, which is our ability, experience, methodology and in the year ended December 31, 2013. Rio das Contas’s 10% working interest creativity to find and develop oil and gas reserves in the subsurface, based in the Manatí Field represented 3,580 boepd of production during 2013. on the best science, solid economics and ability to take the necessary We closed our Rio das Contas acquisition on March 31, 2014. managed risks. • as an Operator, which is our ability to execute in a timely manner and to Separately, in September 2013, we entered into concession agreements with have the know-how to profitably drill for, produce, treat, transport and sell the ANP relating to seven new concessions in the onshore Recôncavo Basin our oil and gas – with the drive and persistence to find solutions, overcome in the State of Bahia and in the onshore Potiguar Basin in the State of Rio obstacles, seize opportunities and achieve results. Grande do Norte, or, our Round 11 concessions, and in November 2013, • as a Consolidator, which is our ability and initiative to assemble the right the ANP awarded us two additional concessions in the Parnaíba Basin in the balance and portfolio of upstream assets in the right hydrocarbon basins State of Maranh(cid:0) o and the Sergipe Alagoas Basin in the State of Alagoas, in the right regions with the right partners and at the right price – coupled subject to confirmation of qualification requirements, or, our Round 12 with the visions and skills to transform and improve value above ground. concessions. See “—Our operations—Operations in Brazil.” We believe that our risk and capital management policies have enabled us to compile a geographically diverse portfolio of properties that balances History We were founded in 2002 by Gerald E. O’Shaughnessy and James F. Park, exploration, development and production of oil and gas. These attributes who have over 25 and 35 years of international oil and natural gas experience, have also allowed us to raise capital and to partner with premier international respectively, and who collectively hold approximately 26% of our common companies. Finally, we believe we have developed a distinctive culture within shares as of the date of this annual report, and are involved in our operations our organization that promotes and rewards partnership, entrepreneurship and strategy. Mr. O’Shaughnessy currently serves as our Chairman and Mr. and merit. Consistent with this approach, all of our employees are eligible Park currently serves as our Chief Executive Officer and Deputy Chairman, and to participate in our long-term incentive program, or our Performance-Based both actively contribute to our ongoing operations and business decisions. Employee Long-Term Incentive Program. See “Item 6. Directors, Senior Management and Employees—B. Compensation—Performance-Based Our history commenced with the purchase of AES Corporation’s upstream Employee Long-Term Incentive Program.” oil and natural gas assets in Chile and Argentina. Those assets included a In Chile, we are the first and the largest non-state controlled oil and gas was operated by the Empresa Nacional de Petróleo, or ENAP, the Chilean producer. We began operations in 2006 in the Fell Block and have evolved state-owned hydrocarbon company, and operating working interests in the from having a non-operated, non-producing interest to having a fully- Del Mosquito, Cerro Doña Juana and Loma Cortaderal blocks in Argentina, operated and producing asset with 10.7 mmboe of net proved reserves as of which we collectively refer to as the Argentina Blocks. Since 2002, our December 31, 2013 and average production of 6,962 boepd in 2013. In business has grown significantly. non-operating working interest in the Fell Block in Chile, which at that time addition, we operate five other hydrocarbon blocks in Chile with significant prospective resources. In 2006, after demonstrating our technical expertise and committing to an exploration and development plan, we obtained a 100% operating In Colombia, following our successful acquisitions of Winchester, Luna and working interest in the Fell Block by the Republic of Chile. Also in 2006, the Cuerva in early 2012, we have an asset base of 10 hydrocarbon blocks where International Finance Corporation, or the IFC, a member of the World Bank we were able to perform an active exploration and development drilling Group, became one of our principal shareholders, and we listed our campaign, which resulted in multiple new oilfield discoveries and to increase common shares on AIM, a market operated by the London Stock Exchange average production from 2,965 boepd for the month of April 30, 2012 (the plc, in an initial public offering of common shares outside the United States. first full month following our Colombian acquisitions) to 7,725 boepd in the Subsequently, in 2008 and 2009, we issued and sold additional common fourth quarter of 2013. Total net production in Colombia averaged 6,491 shares outside the United States. boepd in 2013. As of December 31, 2013, we had net proved reserves of 9.4 mmboe in Colombia. In 2008 and 2009, we continued our growth in Chile by acquiring operating working interests in each of the Otway and Tranquilo Blocks, and by forming Recently, we expanded our footprint to Brazil. In May 2013, we agreed to partnerships with Pluspetrol, Wintershall, Methanex and IFC. acquire Rio das Contas from Panoro, which holds a 10% working interest in the shallow offshore Manatí Field, the largest non-associated gas field in 62 GeoPark 20F In 2010, we formed a strategic partnership with LGI, a Korean conglomerate, On September 30, 2013, we entered into a strategic alliance with Tecpetrol to jointly acquire and develop upstream oil and gas projects in Latin S.A. (the oil and gas subsidiary of the Techint Group) or Tecpetrol, to jointly America. LGI’s business includes a portfolio of energy and raw material identify, study and potentially acquire upstream oil and gas opportunities projects, including oil and gas projects in the Middle East and in Southeast in Brazil, with a specific focus on the Parnaíba, Sao Francisco, Recôncavo, and Central Asia. Potiguar and Sergipe Alagoas basins. Tecpetrol has an extensive track record as an oil and gas explorer and operator throughout the Americas, with a In 2011, ENAP awarded us the opportunity to obtain operating working portfolio of assets in Argentina, Peru, Colombia, Ecuador, Mexico, Bolivia, interests in each of the Isla Norte, Flamenco and Campanario blocks in Venezuela and the United States and current net production of over 85,000 Tierra del Fuego, Chile, which we refer to collectively as the Tierra del Fuego barrels of oil equivalent per day. As part of our strategic alliance with Blocks, and in 2012, jointly with ENAP we entered into special operation Tecpetrol, we expect to enter into an agreement to jointly develop, by contracts (Contratos Especiales de Operación para la Exploración y assigning to Tecpetrol 50% of our working interest in, the PN T 597 Explotación de Yacimientos de Hidrocarburo, or CEOPs) with Chile for the concession in the Parnaíba Basin in the State of Maranh(cid:0) o, which we were exploration and exploitation of hydrocarbons within these blocks. awarded by the ANP, subject to confirmation of qualification requirements. Also in 2011, LGI acquired a 20% equity interest in GeoPark Chile and a 14% 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 Recent developments NYSE Listing In February 2014, we commenced trading on NYSE raising US$98 million to partially secure the US$101.4 million performance bond required by (before underwriting commissions and expenses) through the issuance the Chilean government to guarantee GeoPark TdF’s obligations with respect of 13,999,700 common shares that also included shares issued pursuant to to the minimum work program under the Tierra del Fuego CEOPs. Our the underwriters’ over-allotment option. agreement with LGI in the Tierra del Fuego Blocks allows us to earn back up to 12% equity participation in GeoPark TdF, depending on the success of our operations in Tierra del Fuego. See “Item 10. Additional Information—C. Material contracts.” Acquisition of Rio das Contas On March 31, 2014, we acquired Rio das Contas, which holds a 10% working interest in the BCAM-40 Concession in the shallow-depth offshore Manatí Field in the Camamu-Almada Basin, from Panoro. The total cash consideration In the first quarter of 2012, we moved into Colombia by acquiring three for the acquisition is US$140 million, subject to certain purchase price and privately held E&P companies, Winchester, Luna and Cuerva. These acquisitions easement adjustments. provided us with an attractive platform in Colombia that includes working interests and/or economic interests in 10 blocks located in the Llanos, The Manatí Field, which is in the production phase, is operated by Petróleo Magdalena and Catatumbo Basins and covering an area of 575,700 gross acres. Brasileiro S.A.—Petrobras, or Petrobras (with a 35% working interest), the Brazilian national company and the largest oil and gas operator in Brazil, in In December 2012, LGI acquired a 20% equity interest in GeoPark Colombia for US$20.1 million, including the assumption of existing debt and the partnership with Queiroz Galv(cid:0) o Exploração e Produção, or QGEP (with a 45% working interest), and Brasoil Manatí Exploração Petrolífera S.A., or Brasoil commitment to provide additional funding to cover LGI’s share of required (with a 10% working interest). future investments in Colombia. In addition, our agreement with LGI in Colombia allows us to earn back up to 12% of equity participation in GeoPark We believe the Manatí Field provides us with a strategically important Colombia, depending on the success of our operations in Colombia. upstream asset in Brazil. The shallow offshore Manatí Field is the largest See “Item 10. Additional Information—C. Material contracts.” We and LGI non-associated gas field in Brazil, which produced approximately 7.6% also agreed that we would extend our strategic partnership to build a of the gas produced in Brazil in the year ended December 31, 2013. During portfolio of upstream oil and gas assets throughout Latin America through the years ended December 31, 2012 and 2013, net production attributable 2015. We believe our partnership with LGI represents a positive independent to Rio das Contas in the Manatí Field was approximately 3,677 boepd assessment and validation of the quality of our Chilean and Colombian asset and 3,580 boepd, respectively. inventory, the extent of our technical and operational expertise and the ability of our management to structure and effect significant transactions. Our Rio das Contas acquisition in Brazil provides us with a long-term off-take In May 2013, we entered into agreements to expand our operations to Brazil. reserves in the Manatí Field, a valuable relationship with Petrobras and See “—B. Business overview—Our operations—Operations in Brazil.” an established local platform and presence, with seasoned and experienced contract with Petrobras that covers approximately 74% of net proved gas GeoPark 20F 63 geoscience and administrative team to manage our Brazilian assets and to We have been able to successfully develop our assets through drilling, with seek new growth opportunities. 106 of the 152 wells that we drilled from 2006 through 2013 having become productive wells, a 70% success ratio. We have grown our business through In the year ended December 31, 2013, Rio das Contas generated net income winning new licenses and acquiring strategic assets and businesses, with of approximately US$19.4 million, revenues of approximately US$48.6 million, 15 new blocks incorporated into our portfolio since January 1, 2006, eight and Adjusted EBITDA of approximately US$30.8 million. See "“Item 3. Selected new concessions in Brazil awarded to us following our entry into concession financial data—Unaudited Condensed Combined Pro Forma Financial Data— agreements with the ANP and the closing of our Rio das Contas acquisition. Note 2—Reconciliations.” Since our inception, we have supported our growth through our prospect development efforts and our drilling program, as well as by developing long- In addition to the closing purchase price, the purchase agreement also term strategic partnerships and alliances with key industry participants, provides that for each year from 2013 to and including 2017, we will make accessing debt and equity capital markets and developing and retaining a annual earn-out payments to Panoro in an amount equal to 45% of net technical team with vast experience and a successful track record of finding cash flow, calculated as EBITDA less the aggregate of capital expenditures and producing oil and gas in Latin America. A key factor behind our success and corporate income taxes, with respect to the BCAM-40 Concession of ratio is our experienced team of geologists, geophysicists and engineers, any amounts in excess of US$25.0 million, up to a maximum cumulative including professionals with specialized expertise in the geology of Chile, earn-out amount of US$20.0 million. Colombia, Brazil and Argentina. See “Item 3. Key Information—D. Risk factors—Risks relating to our business” For the year ended December 31, 2013, we drilled 39 new wells, 17 in Chile and “Item 4. Information on the CompanyB. Business overview—Significant and 22 in Colombia) in blocks in which we have working interests and/or agreements—Brazil—Rio das Contas Quota Purchase Agreement” economic interests. Our capital expenditures of US$228.0 million (US$145.7 B. Business overview We are an independent oil and natural gas exploration and production, or respectively) for the year ended December 31, 2013 consisted of US$133.3 million related to exploration, including approximately 1,350 sq. km in 3D E&P, company with operations in Latin America and a proven track record seismic surveys (more than 1,100 sq. km in Chile, mainly related to the blocks of growth in production, reserves and cash flows since 2006. We operate located in Tierra del Fuego and over 250 sq. km in Colombia) million, US$82.1 million and US$0.2 million in Chile, Colombia and Argentina, in Chile, Colombia, Brazil and, to a lesser extent, in Argentina. In March 2014, we invested US$140 million in Brazil, subject to certain We have a well-balanced portfolio of assets that includes working and/or adjustments, to acquire Rio das Contas, which we financed through the economic interests in 27 hydrocarbons blocks, 26 of which are onshore incurrence of a loan of US$70.5 million and cash on hand. blocks, including eleven currently in production, as well as an additional shallow- offshore concession in Brazil that includes the Manatí Field. In 2014, we expect our total capital expenditures, excluding the purchase In addition, we have two new concessions in Brazil that are subject to confirmation of qualification requirements by the ANP. We produced a net price for our Rio das Contas acquisition, to be between US$220 million to US$250 million, of which approximately 62%, 32% and 5% will be in Chile, average of 13,517 boepd during the year ended December 31, 2013, 51.5% Colombia and Brazil, respectively. These capital expenditures will include the of which was produced in Chile, 48% of which was produced in Colombia drilling of 50 to 60 new wells (approximately 40% of which we expect will and 0.5% of which was produced in Argentina, and of which 82% was oil. be exploratory wells), as well as workovers, seismic surveys and new facility Accounting for our Rio das Contas acquisition, on a pro forma basis, we construction. In Brazil, we expect our capital expenditures will consist of would have produced an average of 17,098 boepd during the year ended between US$5 million to US$7.5 million to finance in part the construction December 31, 2013, with Chile, Colombia and Brazil representing 41%, 38% of a gas compression plant in the Manatí Field, and approximately US$0.45 and 21% of our production, respectively, and with oil representing 65% million in license fee payments to the ANP relating to our Round 12 of our total production. As of December 31, 2013, we had net proved concessions, with the remainder for seismic surveys in exploration blocks reserves of 20.1 mmboe (composed of 74% oil and 26% natural gas), of which in the Potiguar and Recôncavo Basins. 10.7 mmboe, or 53%, and 9.4 mmboe, or 47%, were in Chile and Colombia, respectively. Additionally, according to the D&M Reserves Report, as of For the year ended December 31, 2013, our average oil and gas production December 31, 2013, Rio das Contas had net proved reserves of 8.3 mmboe totaled 13,517 boepd, a 20% increase as compared to our average oil and gas (composed of approximately 98% natural gas). production for the year ended December 31, 2012 of 11,292 boepd. Oil and liquids represented 82% and 66% of our total oil and gas production for the 64 GeoPark 20F years ended December 31, 2013 and 2012, respectively. Oil production 2014, our average oil and gas production for the year ended December 31, increased by 48% to 11,113 bopd (consisting of 4,581 bopd, 6,482 bopd and 2013 reached 17,098 boepd (consisting of 11,173 bopd of oil and 35,539 50 bopd in Chile, Colombia and Argentina, respectively) for the year ended mcfpd of gas), with oil and liquids representing 65% of total production. December 31, 2013, as compared to 7,491 bopd for the year ended December 31, 2012. Gas production increased to 14,419 mcfpd (consisting of 14,283 The following map shows the countries in which we have blocks with working mcfpd, 52 mcfpd and 84 mcfpd in Chile, Colombia and Argentina, and/or economic interests as of December 31, 2013 and also includes our respectively) for the year ended December 31, 2013. On a pro forma basis, Brazil Acquisitions. For information on our working interests in each of these accounting for our Rio das Contas acquisition, which closed on March 31, 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 Arrendajo Abanico Cerrito Jagüeyes Chile Blocks Fell Tranquilo Otway Isla Norte Campanario Flamenco B R A Z I L 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 Asset Type / Work Program Production Development Exploration Unconventional resource New projects inventory Brazil Blocks(1) POT - T 619 POT - T 620 POT - T 663 POT - T 664 POT - T 665 REC - T 85 REC - T 94 BCAM - 40 (Manatí) SEAL - T 268 PN - T 597 A T L A N T I C O C E A N Argentina Blocks Del Mosquito Cerro Doña Juana Loma Cortaderal (1) We closed the acquisition of Rio das Contas on March 31, 2014. We have concessions, subject to confirmation of qualification requirements and also entered into seven new concession agreements with the ANP in absence of legal impediments, by the ANP in the Parnaíba Basin and the the Recôncavo and Potiguar Basins in Brazil and were awarded, two new Sergipe Alagoas Basin. See “—Our operations—Operations in Brazil.” GeoPark 20F 65 The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2013, and also includes on a pro forma basis information on our recent Rio das Contas acquisition, which closed on March 31, 2014. Country Chile Colombia Argentina Total Brazil(1) Pro forma total Oil (mmbbl) 5.4 9.4 0.0 14.8 0.2 15.0 Gas (bcf) 32.2 0.0 0.0 32.2 48.8 80.9 equivalent (mmboe) 10.7 9.4 0.0 20.1 8.3 28.4 For the year ended December 31, 2013 Revenues (in thousands of US$) 157,491 179,324 1,538 338,353 48,570 386,923 % Oil 50% 100% — 74% 2% 53% % of total revenues 47% 53% — 100% — — (1) Reflects our Rio das Contas acquisition. As of December 31, 2013, according to the D&M Reserves Report, the net proved reserves attributable to our Rio das Contas acquisition in Brazil were 8.3 mmboe (composed of approximately 98% natural gas), which generated revenues of US$48.6 million for the year ended December 31, 2013. Our commitment to growth has translated into a strong compounded annual growth rate, or CAGR, of 45.9% for production in the period from 2007 to 2013, as measured by boepd in the table below. Average net production (mboepd) % oil 2013 13.5 82.2% 2012 11.3 66.3% 2011 7.6 33.0% 2010 6.9 28.4% 2009 6.3 19.5% 2008 3.4 9.8% 2007 1.4 12.0% For the year ended December 31, During the year ended December 31, 2013, Rio das Contas, whose production is not accounted for in the table above, produced 3.6 mboepd. 66 GeoPark 20F The following table sets forth our production of oil and natural gas in the The following table sets forth the pro forma evolution of our net proved blocks in which we have a working and/or economic interest as of December reserves of natural gas as of and for the year ended December 31, 2013, as 31, 2013. adjusted for the acquisition of Rio das Contas on December 31, 2013. Oil production Total crude oil production (bopd) Average sales price of crude oil (US$/bbl) Natural gas production Total natural gas production (mcf/day) Average sales price of natural gas Average daily production For the year ended December 31, 2013 Chile Colombia Argentina 4,581 6,482 50 84.3 80.3 70.3 Reserves as of December 31, 2012 Increase (decrease) attributable to: Revisions 14,283 52 84 Extensions and discoveries Purchases (US$/mcf) 5.0 4.18 1.1 Production Oil and natural gas production cost Weighted average Pro Forma Reserves as of December 31, 2013 production cost (US$/boe) 26.6 47.2 14.8 Net proved reserves (developed and undeveloped) of natural gas Rio das GeoPark Contas Pro Forma historical historical combined (mmcf) 29,581.0 51,762.9 81,343.9 4,691.0 2,219.0 — 4,712.9 — — 9,403.9 2,219.0 — (4,332.0) (7,708.8) (12,040.8) 32,159.0 48,767.0 80,926.0 During the year ended December 31, 2013, average daily production of Our assets According to the D&M Reserves Report, as of December 31, 2013, the blocks Rio das Contas was 21,120 mcf/day with an average sales price of natural gas in Chile, Colombia and Argentina in which we have a working interest had of 6.4 US$/mcf. In addition, weighted average production cost was 27.0 20.1 mmboe of net proved reserves, with 10.7 mmboe, or 53%, and 9.4 (US$/boe). Pro Forma net proved reserves mmboe, or 47%, of such net proved reserves located in Chile and Colombia, respectively. Giving effect to our Rio das Contas acquisition on a pro forma basis, we would have net proved reserves of 28.4 mmboe as of December 31, 2013, with Chile, Colombia and Brazil representing 38%, 33% and 29% of net Pro Forma net proved reserves of oil, condensate and natural gas The following table sets forth the pro forma evolution of our net proved proved reserves, respectively. reserves of oil and condensate as of and for the year ended December 31, For the year ended December 31, 2013, we produced an average of 13,517 2013, as adjusted for the acquisition of Rio das Contas at December 31, 2013. boepd, of which 6,962 boepd, or 52%, was produced in the Fell Block, 6,491 boepd, or 48%, was produced in the Colombian blocks and 64 boepd, Net proved reserves or 0.5%, was produced in the Argentine blocks. Giving effect to our Rio das (developed and undeveloped) Contas acquisition on a pro forma basis, we would have produced an of oil and condensate average of 17,098 boepd during the year ended December 31, 2013, with Rio das Chile, Colombia and Brazil representing 41%, 38% and 21% of our production, GeoPark Contas Pro Forma respectively, and with oil representing 65% of our total production. historical historical combined 11,885.1 134.3 12,019.4 interest. The following table summarizes certain information about our (mbbl) We are the operator of a majority of the blocks in which we have a working (5.9) 6,641.0 — 37.8 — — Chilean, Colombian and Argentine blocks as of December 31, 2013, and also 31.9 includes on a pro forma basis information on our recent Rio das Contas 6,641.0 acquisition. — (3,718.6) (22.1) (3,740.7) 14,801.6 150.0 14,951.6 Reserves as of December 31, 2012 Increase (decrease) attributable to: - Revisions - Extensions and discoveries - Purchases of minerals in place - Production Pro Forma Reserves as of December 31, 2013 GeoPark 20F 67 Country Concession Operator Block/ Working interest (1)(2)(12) Basin Gross area Net proved (thousand acres)(3) 367.8 reserves (mmboe)(4) 10.7 Net production (boepd)(5) 6,962 % Oil 50% Fell Tranquilo(19) Otway GeoPark GeoPark GeoPark 100% Magallanes 29% Magallanes 100% Magallanes 92.4 49.4(6) Isla Norte GeoPark 60%(7) Magallanes 130.2 Campanario GeoPark 50%(7) Magallanes 192.2 Flamenco(20) GeoPark 50%(7) Magallanes 141.3 — — — — — — — — — — — — — — — Concession % Oil expiration year 66% Exploitation: 2032 — Exploitation: 2043 — Exploitation: 2044 Exploration: 2019 — Exploitation: 2044 Exploration: 2020 — Exploitation: 2045 Exploration: 2019 — Exploitation: 2044 Chile Chile Chile Chile Chile Chile Subtotal Chile 973.3 10.7 50% 6,962 66% Colombia La Cuerva GeoPark 100% Llanos Colombia Llanos 34 GeoPark 45% Llanos Colombia Llanos 62 GeoPark 100% Llanos Colombia Yamú GeoPark 54.5/75%(8) Llanos 47.8 82.2 44.0 11.2 Exploration: 2014 2.6 100% 1,962 100% Exploitation: 2038 Exploration: 2015 6.4 — 0.3 100% 3,469 100% Exploitation: 2039 — — — Exploitation: 2041 Exploration: 2017 Exploration: 2013 100% 550 100% Exploitation: 2036 Exploration: 2015 Colombia Llanos 17 RIL-Parex 36.8%(9) Llanos 108.8 0.03 100% 49 — Exploitation: 2039 0%(10) Llanos 100.3 0.06 100% 180 100% Exploitation: 2039 Exploration: 2015 Colombia Llanos 32 Jagüeyes Verano Energy Colombia 3432A Columbus 5% Llanos Arrendajo Abanico Cerrito Pacific Pacific Pacific 0%(11) Llanos 0%(11) Magdalena 0%(11) Catatumbo Colombia Colombia Colombia Subtotal Colombia Argentina Del Mosquito GeoPark 100% Austral Cerro Doña Juana(18) Loma Cortaderal(18) GeoPark 100% Neuquén GeoPark 100% Neuquén Argentina Argentina Subtotal Argentina 68 GeoPark 20F 61.0 78.1 32.1 10.2 — — — — — — — — — 177 95 9 Exploration: 2014 — Exploitation: 2038 Exploration: 2017 100% Production: 2041 100% Production: 2022 0% Production: 2028 575.7 9.4 100% 6,491 100% 17.3 19.6 28.3 65.2 — — — — — — — — 64 — — 64 78% Exploitation: 2016 — Exploitation: 2017 — Exploitation: 2017 78% Country Concession Operator Block/ Working interest (1)(2)(12) Gross area Net proved (thousand acres)(3) reserves (mmboe)(4) Basin Net production (boepd)(5) % Oil Concession % Oil expiration year Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Subtotal Brazil Total GeoPark Brazil Total GeoPark Pro forma REC T 94 GeoPark 100% Recôncavo REC T 85 GeoPark 100% Recôncavo POT T 664 GeoPark 100% Potiguar POT T 665 GeoPark 100% Potiguar POT T 619 GeoPark 100% Potiguar POT T 620 GeoPark 100% Potiguar POT T 663 GeoPark PN T 597(15) GeoPark(16) 100% 100%(16) SEAL T 268(15) GeoPark Potiguar Parnaíba Sergipe Alagoas Camamu- 7.7 7.7 7.9 7.9 7.9 7.9 7.9 188.7 7.8 251.4 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — Exploration: 2018 — Exploitation: 2045 Exploration: 2018 — Exploitation: 2045 Exploration: 2018 — Exploitation: 2045 Exploration: 2018 — Exploitation: 2045 Exploration: 2018 — Exploitation: 2045 Exploration: 2018 — Exploitation: 2045 Exploration: 2018 — Exploitation: 2045 —(15) — — — —(15) 1,865.6 20.1 74% 13,517 82% Exploitation: 2029(13) 2034(14) BCAM 40 Petrobras(17) 10% Almada 22.8 8.3 2% 3,580 2% 1,888.4 28.4 53% 17,098 65% (1) Working interest corresponds to the working interests held by our Ministry of Energy granted this permit, such that, upon execution of a deed respective subsidiaries in such block, net of any working interests and/or of assignment of rights containing the as-approved terms, we will be the sole economic interests held by other parties in such block. (2) As of the date of this annual report, LGI has a 20% equity interest in our participant, and have a 100% working interest, in our two remaining areas under the Otway Block CEOP. See “—Our operations—Operations in Chile— Chilean operations through GeoPark Chile and a 20% equity interest in Otway and Tranquilo Blocks.” our Colombian operations through GeoPark Colombia. (7) LGI has a 14% direct equity interest in our Tierra del Fuego operations (3) Gross area refers to the total acreage of each block. through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for a (4) Reflects net proved reserves as of December 31, 2013. total 31.2% effective equity interest in our Tierra del Fuego operations. See (5) Reflects net average production for 2013. Net production refers to average “—Our operations—Operations in Chile—Tierra del Fuego Blocks (Isla Norte, production for each block, net of any working interests or economic interests Campanario and Flamenco Blocks).” held by others in such block but gross of any royalties due to others. (8) Although we are the sole title holder of the working interest in the Yamú (6) In April 2013, we voluntarily relinquished to the Chilean government all Block, other parties have been granted economic interests in fields in this of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our block. Taking those other parties’ interests into account, we have a 54.5% partners under the joint operating agreement governing the Otway Block interest in the Carupana Field and a 75% interest in the Yamú and Potrillo decided to withdraw from such joint operating agreement, and applied for an Fields, both located in the Yamú Block. assignment of rights permit on August 5, 2013. On August 26, 2013, the (9) We currently have a 40% working interest in the Llanos 17 Block, although GeoPark 20F 69 we have assigned a 3.2% economic interest to a third party. We expect to apply to formalize this assignment with the ANH so that it will be recognized Our strengths We believe that we benefit from the following competitive strengths: as a working interest. (10) We currently have a 10% economic interest in the Llanos 32 Block, High quality and diversified asset base built through a successful track although we have applied to the ANH to recognize this as a working interest in the block, and expect to receive the ANH’s authorization in the first half record of organic growth and acquisitions Our assets include a diverse portfolio of oil- and natural gas-producing of 2014. reserves, operating infrastructure, operating licenses and valuable geological (11) We do not have a working interest in those blocks, though we have a surveys. According to the D&M Reserves Report, as of December 31, 2013, 10% economic interest in the net revenues of each of these blocks pursuant we had 20.1 mmboe of net proved reserves in Chile and Colombia, of which to various partnership interests’ agreements. See “—Our operations— 74%, or 14.8 mmboe, was oil, and 26%, or 5.3 mmboe, was gas and of which Operations in Colombia.” 50%, or 7.1 mmboe, was net proved developed reserves. In addition, on (12) Working interest corresponds to the working interests we expect to a pro forma basis, after giving effect to our Rio das Contas acquisition, as hold in such concession, net of any working interests held by other parties of December 31, 2013, we had 28.4 mmboe of net proved reserves in Brazil, in such concession, as a result of our Rio das Contas acquisition and Round Chile and Colombia, of which 53%, or 15.0 mmboe, was oil, and 47%, or 12 concessions (13) Corresponds to the Manatí Field. (14) Corresponds to the Camarão Norte Field. 13.4 mmboe, was gas and of which 42%, or 12.1 mmboe, was net proved developed reserves. Throughout our history, we have delivered continuous growth in our production, and our management team has been able to (15) Round 12 concessions are subject to confirmation of qualification identify under-exploited assets and turn them into valuable, productive requirements by the ANP and absence of any legal impediments to signing. assets. For example, in 2002, we acquired a non-operating working interest See “Item 3. Key information—D. Risk factors—Risks relating to our business— in the Fell Block in Chile, which at the time had no material oil and gas The PN-T-597 concession is subject to an injunction and may not close.” production or reserves despite having been actively explored and drilled over (16) We expect to jointly develop this concession with Tecpetrol and assign the course of more than 50 years. Since 2006, when we became the operator 50% of our working interest in this concession to Tecpetrol. of the Fell Block, through 2013, we have invested more than US$410 million (17) We closed the Rio das Contas acquisition on March 31, 2014. Partners: and drilled approximately 95 wells in the block, with 73% of such wells Petrobras; QGEP and Brasoil. becoming productive during that period. Currently, we are the operator and (18) In April 2014, we informed the Secretary of Infrastructure and Energy of sole concessionaire of the Fell Block, which, during the year ended December the province of Mendoza of our decision to relinquish 100% of the Cerro 31, 2013, produced approximately 6,962 boepd. As of December 31, 2013, we Doña Juana and Loma Cortaderal Concessions to the Mendoza Province. generated 66% of Chile’s total oil production and 16% of its gas production, (19) On December 31, 2013, the Consortium members and interest were: according to information provided by the Chilean Ministry of Energy. GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. Methanex and Wintershall have recently announced its decision to exit the Consortium. The acquisitions of Winchester, Luna and Cuerva in Colombia in the first The new ownership is being negotiated among us and Pluspetrol. (20) In 2013, there were new discoveries in the Flamenco block. However, quarter of 2012 gave us access to an additional 574,979 gross exploratory and productive acres across 10 blocks in what we believe to be one of South there are no proved reserves estimated for this block due to incomplete America’s most attractive oil and gas geographies. According to the D&M testing of these wells as of the date of this annual report. Reserves Report, as of December 31, 2013, the blocks in Colombia in which we have a working interest had 9.4 mmboe of net proved reserves, all of which were in oil. Since we acquired Winchester, Luna and Cuerva, we were able to perform an active exploration and development drilling campaign, which resulted in multiple new discoveries and to increase average production to 6,962 boepd in Colombia in 2013. 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 that had not been successfully tested before in the Llanos basin. 70 GeoPark 20F In addition, in line with our growth strategy, on March 31, 2014 we closed additional wells in the formation and we plan to continue to explore this the acquisition of Rio Das Contas, which gave us a 10% working interest formation, which has been the focus of our drilling plan. See “—Our in the BCAM-40 Concession, including the shallow-depth offshore Manatí and operations” We have also initiated a technical assessment of the oil and gas Camarão Norte Fields, in the Camamu-Almada Basin in the State of Bahia. shale potential in the Estratos con Favrella shale formation in some of our The Manatí Field, which is in the production phase, is operated by Petrobras blocks in Chile. (with a 35% working interest), the Brazilian national company and the largest oil and gas operator in Brazil, in partnership with QGEP (with a 45% working • In Colombia, in 2013, following our identification of several leads and interest), and Brasoil (with a 10% working interest). See “—Significant prospects in our Llanos 34 Block, our most prospective Colombian block, agreements—Brazil—Rio das Contas Quota Purchase Agreement.”Our Rio we completed a 3D seismic survey on most of the remaining 50% of the das Contas acquisition in Brazil provides us with a long-term off-take contract acreage that had not been previously surveyed. Furthermore, in the second with Petrobras that covers approximately 74% of net proved gas reserves in quarter of 2013, we successfully put into production our third discovery, the Manatí Field, a valuable relationship with Petrobras and an established the Potrillo 1 well in the Yamú Block, and our fourth discovery, the Tarotaro 1 local platform and presence, with seasoned and experienced geoscience and well in the Llanos 34 Block. In addition, in the fourth quarter of 2013, we administrative team to manage our Brazilian assets and to seek new growth drilled and tested the Tigana 1 exploration well in the Mirador and opportunities. According to the D&M Reserves Report, as of December 31, Guadalupe formations, our fifth new oil field discovery, and the Tigana Sur 1 2013, BCAM-40 Concession had 8.3 mmboe of net proved reserves, exploration well in the Guadalupe formation, our sixth new oil field discovery (composed of approximately 98% natural gas). See “—Our operations— in Colombia, both in the Llanos 34 Block. See “—Our operations. Operations in Brazil.” Significant drilling inventory and resource potential from existing that were entered into with the ANP, and we expect to begin seismic surveys • In Brazil, in 2013 we were awarded seven new exploratory concessions asset base Our portfolio includes large land holdings in high-potential hydrocarbon in these blocks in 2014. basins and blocks with multiple drilling leads and prospects in different Our geoscience team continues to identify new potential accumulations and geological formations, which provide a number of attractive opportunities expand our inventory of prospects and drilling opportunities. with varying levels of risk. Our drilling inventory consists of over 200 identified drilling locations, and our development plans target locations that we believe are low-cost, provide attractive economics and support a Strong liquidity and financial flexibility to fund expansion We benefit from both historically consistent cash flows and access to debt predictable production profile. Currently, we are executing our most and equity capital markets, as well as other funding sources, which have significant exploration and drilling plan to date: provided us with strong liquidity and the financial flexibility to finance our • In Chile, in 2013, we completed a 3D seismic survey covering approximately US$140.1 million and US$131.8 million in cash from operations in the years 315,000 gross acres, or 68% of the gross acres in our Tierra Del Fuego Blocks. Part of the survey took place in the Flamenco Block, where we drilled our first ended December 31, 2013 and 2012, respectively, and had US$121.1 million and US$38.3 million in cash and cash equivalents as of December 31, 3013 organic growth and the pursuit of potential new opportunities. We generated successful exploratory well (Chercán 1), which resulted in our first oil and and 2012, respectively. gas discovery in Tierra del Fuego. We have completed the construction of a flowline to connect this well to existing infrastructure, and the well is In March 2014, we borrowed US$70.5 million pursuant to a five-year term currently producing approximately 2,650 mcfpd. We subsequently drilled variable interest secured loan, secured by the benefits GeoPark receives under two additional exploratory wells in the Flamenco Block (Omeling 1 and the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to Yakamush 1), which are on standby for workover activities. Our Tierra del six-month LIBOR + 3.9% to finance part of the purchase price of our Rio das Fuego Blocks have similar geological characteristics to the Fell Block, and we Contas acquisition, and funded the remaining amount with cash on hand. intend to replicate the exploration and development strategy we successfully executed in the Fell Block in these blocks. In 2011, we expanded into a In February 2014, we commenced trading on the NYSE and raised US$98 new play concept following our first oil discovery in the Konawentru well in million (before underwriting commissions and expenses), including the over the Tobífera formation, a volcaniclastic reservoir that lies below the Springhill allotment option granted to and exercised by the underwriters, through formation, the traditional sandstone of the Magallanes Basin. Since then, the issuance of 13,999,700 common shares. we have significantly increased our oil production from the drilling of GeoPark 20F 71 In 2010, we issued US$133.0 million aggregate principal amount of 7.75% Our Chairman, Mr. Gerald O’Shaughnessy, has been actively involved in the senior secured notes in the international markets, or the Notes due 2015, oil and gas business internationally and in North America since 1976. which were redeemed following our issuance in 2013 of US$300.0 million As of the date of this annual report, Mr. O’Shaughnessy held 13.2% of our aggregate principal amount of 7.50% senior secured notes due 2020, or outstanding common shares. the Notes due 2020. In 2007, we obtained financing from Methanex Chile S.A., or Methanex, industry of approximately 25 years in companies such as Chevron, San Jorge, the Chilean subsidiary of the Methanex Corporation, a leading global Petrobras, Total, Pluspetrol, ENAP and YPF, among others. Throughout our methanol producer, in an amount of US$40 million, structured as a gas history, our management and operating team has had success in unlocking pre-sale agreement with a six-year term at an interest rate equal to unexploited value from previously underdeveloped assets. Our management and operating team has an average experience in the energy the six-month LIBOR. In 2006, we completed an initial public offering of our common shares management and employees (excluding our founding shareholders, outside the United States on AIM and, in 2008 and 2009, we issued and sold Mr. Gerald E. O’Shaughnessy and Mr. James F. Park) owned 6.6% of our additional common shares outside the United States. outstanding common shares, aligning their interests with those of our In addition, as of the date of this annual report, our executive directors, shareholders and helping retain the talent we need to continue to support In February 2006, the IFC became a significant shareholder by contributing our business strategy. See “Item 6. Directors, Senior Management and US$10 million. Later that year, we entered into a loan agreement for Employees—B. Compensation.” Our founding shareholders are also US$20 million with the IFC, which we have since fully repaid, to partially involved in our daily operations and strategy. finance our investment program. Long-term strategic partnerships and strong strategic relationships, Highly committed founding shareholders and technical and management such as with LGI, provide us with additional funding flexibility to pursue teams with proven industry expertise and technically-driven culture Our founding shareholders, management and operating teams have further acquisitions We benefit from a number of strong partnerships and relationships. In March significant experience in the oil and gas industry and a proven technical and 2010, we entered into a framework agreement with LGI to establish a commercial performance record in onshore fields, as well as complex projects strategic growth partnership to jointly acquire and invest in oil and natural in Latin America and around the world, including expertise in identifying gas projects throughout Latin America. In May 2011, our partnership with acquisition and expansion opportunities. Moreover, we differentiate LGI was strengthened by LGI’s acquisition of a 10% equity interest in our ourselves from other E&P companies through our technically-driven culture, existing Chilean operations. In October 2011, LGI acquired an additional which fosters innovation, creativity and timely execution. Our geoscientists, 10% equity interest in GeoPark Chile and a 14% equity interest in GeoPark geophysicists and engineers are pivotal to the success of our business TdF, and agreed to provide additional financial support for the further strategy, and we have created an environment and supplied the resources that enable our technical team to focus its knowledge, skills and experience development of the Tierra del Fuego Blocks. In December 2012, LGI acquired a 20% equity interest in our Colombian business. We also agreed with LGI on finding and developing oil and gas fields. to extend our strategic partnership in order to build a portfolio of upstream oil and gas assets throughout Latin America through 2015. We are currently In addition, we strive to provide a safe and motivating workplace for the only independent E&P company in which LGI has equity investments employees in order to attract, protect, retain and train a quality team in the in Latin America. See “Item 4. Information on the Company—B. Business competitive marketplace for capable energy professionals. overview—Significant agreements—Agreements with LGI” for additional Our CEO, Mr. James Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, In addition, the IFC has been one of our shareholders since 2006, holding drilling and production operations, surface and pipeline construction, an 8% equity interest in us. In Chile, we have strong long-term commercial legal and regulatory issues, crude oil marketing and transportation and relationships with Methanex and ENAP, and in Colombia, through our capital raising for the industry. As of the date of this annual report, Mr. Park acquisitions of Winchester, Luna and Cuerva, we have inherited a strong held 12.9% of our outstanding common shares. relationship with Ecopetrol, the Colombian state-owned oil and information relating to these agreements. gas company. 72 GeoPark 20F In Brazil, the closing of our Rio das Contas acquisition on March 31, 2014 of lower-risk cash flow-generating properties and assets that have upside leads us to believe we will derive substantial benefits from Rio das Contas’s potential, keeping a balanced mix of oil- and gas-producing assets (though long-term relationship with Petrobras. Additionally, we have entered into we expect to remain weighted toward oil) and focusing on both assets and a strategic alliance with Tecpetrol, to jointly identify, study and potentially corporate targets. acquire upstream oil and gas opportunities in Brazil. As part of our strategic alliance with Tecpetrol, we expect to enter into an agreement to jointly Continue to foster a technically-driven culture and to capitalize on local develop, by assigning to Tecpetrol 50% of our working interest in, the PN T 597 concession in the Parnaíba Basin in the State of Maranhão, which knowledge We intend to continue to build and strengthen an environment that will we were awarded by the ANP, subject to confirmation of qualification allow us to fully consider and understand risk and reward and to deliberately requirements. See “—Our operations—Operations in Brazil.” and collectively pursue strategies that maximize value. For this purpose, Our strategy we intend to continue expanding our technical teams and to foster a culture that rewards talent according to results. For example, we have been able to maintain the technical teams we inherited through our Colombian Continue to grow a risk-balanced asset portfolio We intend to continue to focus on maintaining a risk-balanced portfolio of acquisitions and intend to retain our technical teams in Brazil after acquiring Rio das Contas on March 31, 2014. We believe local technical assets, combining cash flow-generating assets with upside potential and professional knowledge is key to operational and long-term success opportunities, and on increasing production and reserves through finding, and intend to continue to secure local talent as we grow our business developing and producing oil and gas reserves in the countries in which we in different locations. operate. For example, through our recent expansion into Brazil, we have secured steady cash flows through our acquisition of Rio das Contas, as well as exploratory potential through our success in two ANP oil and gas bidding Maintain a high degree of operatorship We currently are, and intend to continue to be, the operator of a majority rounds in which we were awarded a total of nine concessions in Brazil. of the blocks and concessions in which we have working interests. Operating We believe this approach will allow us to sustain continuous and profitable the majority of our blocks and concessions gives us the flexibility to allocate growth and also participate in higher risk growth opportunities with upside our capital and resources opportunistically and efficiently. We believe potential. See “—Our operations.” Maintain conservative financial policies We seek to maintain a prudent and sustainable capital structure and a that this strategy has allowed, and will continue to allow, us to leverage our unique culture and our talented technical, operating and management teams. As of December 31, 2013, 99.6% of our net proved reserves and 96% of our production came from blocks in which we are the operator. On a strong financial position to allow us to maximize the development of our pro forma basis, accounting for our Rio das Contas acquisition, approximately assets and capitalize on business opportunities as they arise. We intend 71% of our production as of December 31, 2013 would have come from to remain financially disciplined by limiting substantially all our debt blocks that we operate. incurrence to identified projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers in addition to the international capital markets. Maintain our commitment to environmental and social responsibility A major component of our business strategy is our focus on our environmental and social responsibility. We are committed to minimizing Pursue strategic acquisitions in Latin America We have historically benefited from, and intend to continue to grow through, the impact of our projects on the environment. We also aim to create mutually beneficial relationships with the local communities in which strategic acquisitions. Our Colombian acquisitions highlight our ability to we operate in order to enhance our ability to create sustainable value in identify and execute opportunities at what we believe to be attractive prices. our projects. In line with the IFC’s standards, our commitment to our These acquisitions have provided us with, and we expect that our Brazil environmental and social responsibilities is a major component of our Acquisitions will provide us with, attractive platforms in those countries. business strategy. These commitments are embodied in our in-house Our enhanced regional portfolio, primarily in investment-grade countries, designed Environmental, Health, Safety and Security management program, and strong partnerships position us as a regional consolidator. We intend to which we refer to as “S.P.E.E.D.” (Safety, Prosperity, Employees, Environment continue to grow through strategic acquisitions and potentially in other and Community Development). Our S.P.E.E.D. program was developed in countries in Latin America, including Peru which has an investmentgrade accordance with several international quality standards, including ISO 14001 rating. Our acquisition strategy is aimed at maintaining a balanced portfolio for environmental management issues, OHSAS 18001 for occupational health GeoPark 20F 73 and safety management issues, SA 8000 for social accountability and workers’ rights issues, and applicable World Bank standards. See “—Health, safety and environmental matters.” Our operations We have a well-balanced portfolio of assets that includes working and/or economic interests in 27 hydrocarbons blocks, 26 of which are onshore blocks, including eleven currently in production, as well as in an additional shallow-offshore concession in Brazil that includes the Manatí Field. In addition, we have two new concessions in Brazil that are subject to confirmation of qualification requirements by the ANP. Operations in Chile We became the first privately-owned oil and gas producer in Chile when we began production in the Fell Block in May 2006, and, for the year ended December 31, 2013, we produced 66% 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 an important platform for continued growth and expansion in that country. The map below shows the location of the blocks in Chile in which we have working interests. 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 74 GeoPark 20F 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, 2013. Block Fell Tranquilo Otway Isla Norte Campanario Flamenco(7) Gross acres Working (thousand acres) 367.8 interest (1)(6) 100% Net proved reserves Production (boepd) Basin 6,962 Magallanes Exploitation: 2032 Concession expiration year Partners(2) — Pluspetrol; Operator GeoPark (mmboe)(3) 10.7 92.4 (4)49.4 Wintershall; (6)29% Methanex (5)100% — GeoPark GeoPark 130.2 (5)60% ENAP GeoPark 192.2 (5)50% ENAP GeoPark 141.3 (5)50% ENAP GeoPark — — — — — — Magallanes — Magallanes Exploitation: 2043 Exploitation: 2044 Exploration: 2019 — Magallanes Exploitation: 2044 Exploration: 2020 — Magallanes Exploitation: 2045 — Magallanes Exploitation: 2044 Exploration: 2019 1) Working interest corresponds to the working interests held by our and Wintershall have recently announced its decision to exit the Consortium. respective subsidiaries in such block, net of any working interests held by The new ownership is being negotiated among us and Pluspetrol. other parties in such block. LGI has a 20% direct equity interest in our (7) In 2013, there were new discoveries in the Flamenco block. However, Chilean operations through GeoPark Chile. See “—Significant agreements— there are no proved reserves estimated for this block due to incomplete Agreements with LGI—LGI Chile Shareholders’ Agreements.” testing of these wells as of the date of this annual report. (2) Partners with working interests. (3) As of December 31, 2013. Our Chilean blocks are located in the provinces of Ultima Esperanza, (4) In April 2013, we voluntarily relinquished to the Chilean government all Magallanes and Tierra del Fuego in the Magallanes Basin, a proven oil- and of our acreage in the Otway Block, except for 49,421 acres. In May 2013, gas-producing area. As of December 31, 2013, the Magallanes Basin our partners under the joint operating agreement governing the Otway Block accounted for all of Chile’s oil and gas production. Although this basin has decided to withdraw from such joint operating agreement, and applied been in production for over 60 years, we believe that it remains relatively for an assignment of rights permit on August 5, 2013. On August 26, 2013, underdeveloped. the Ministry of Energy granted this permit, such that, upon the execution of a deed of assignment of rights containing the asapproved terms, we will be Substantial technical data (seismic, geological, drilling and production the sole participant, and have a 100% working interest, in our two remaining information), developed by us and by ENAP, provides an informed base for areas under the Otway Block CEOP. See “—Otway and Tranquilo Blocks.” new hydrocarbon exploration and development. Shut-in and abandoned fields (5) LGI has a 14% direct equity interest in our Tierra del Fuego operations may also have the potential to be put back in production by constructing through GeoPark TdF and a 20% direct equity interest in GeoPark Chile, for a new pipelines and plants. Our geophysical analyses suggest additional total effective equity interest of 31.2% in our Tierra del Fuego operations. development potential in known fields and exploration potential in undrilled See “—Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks)” prospects and plays, including opportunities in the Springhill, Tertiary, Tobífera and “—Significant agreements—Agreements with LGI—LGI Chile and Estratos con Favrella formations. The Springhill formation has historically Shareholders’ Agreements.” been the source of production in the Fell Block, though the Estratos con (6) At 31 December 2013, the Consortium members and interest were: Favrella shale formation is the principal source rock of the Magallanes Basin, GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. Methanex and we believe it contains unconventional resource potential. GeoPark 20F 75 Fell Block In 2006, we became the operator and 100% interest owner of the Fell Block. During the last three months of 2012 and throughout 2013, we continued our exploration and development from the Tobífera formation by drilling wells When we first acquired an interest in the Fell Block in 2002, it had no material in Konawentru, Yagán and Yagán Norte fields, as well as deepening existing oil and gas production. Since then, we have completed more than 1,100 sq. wells in Ovejero and Molino fields with stable production from the formation, km of 3D seismic surveys and drilled 95 exploration and development wells. and successful workovers in the Tetera and Kiuaku fields. We are also In the year ended December 31, 2013, we produced an average of evaluating the Estratos con Favrella shale reservoir, which we believe approximately 14,283 mcfpd of gas and 4,581 bopd of oil, or 6,692 boepd, represents a high-potential, unconventional resource play for shale oil and in the Fell Block. gas, as a broad area of the Fell Block (1,000 sq. km) appears to be in the oil window for this play. We have begun work to reinterpret core data logs The Fell Block has an area of approximately 368,000 gross acres (1,488 sq. km) and well test information, evaluate cores and fluids and determine and its center is located approximately 140 km northeast of the city of Punta reservoir brittleness (for fracturing) through special field tests. Arenas. It is bordered on the north by the international border between Argentina and Chile and on the south by the Strait of Magellan. Additionally, we have installed ESPs in some key wells in the Fell Block, The first exploration efforts began on the Fell Block in the 1950s. Through generating positive results and increasing our oil production in those 2005, ENAP carried out seismic surveys and drilled numerous wells in wells. Our team is working on identifying other Tobifera wells where to which we believe were the first-ever ESPs to be used in Chile and which are the block. From 2006 through August 2011, we invested approximately replicate these results. US$210 million in exploring and developing the Fell Block, which allowed us to transition approximately 84% of the Fell Block’s area from an exploration phase into an exploitation phase, which we expect will last Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks) In the first and second quarters of 2012, we entered into three CEOPs with through 2032. During the exploration phase, we exceeded the minimum ENAP and Chile granting us working interests in the Isla Norte, Campanario work and investment commitment required under the Fell Block CEOP and Flamenco Blocks, located in the center-north of the Tierra del Fuego by more than 75 times, and as of December 31, 2013, had invested more province of Chile. We are the operator of all three of these blocks, with than US$410 million in the Fell Block. There are no minimum work and working interests of 60%, 50% and 50%, respectively. We believe that these investment commitments under the Fell Block CEOP associated with the three blocks, which collectively cover 463,700 gross acres (1,877 sq. km) exploitation phase. and are similar and geologically contiguous to the Fell Block, represent strategic acreage with high resource potential. Following the successful Geologically, the Fell Block is located in the north-eastern part of the methodology we employed on the Fell Block, we expect to evaluate early Magallanes Basin. The principal producing reservoir is composed by production opportunities from existing nonproducing wells in Tierra del sandstones in the Springhill formation, at depths of 2,200 to 3,500 meters. Fuego. We have committed to paying 100% of the required minimum Additional reservoirs have been discovered and put into production in investment under the CEOPs covering these blocks, in an aggregate amount the Fell Block—namely, Tobífera formation volcaniclastic rocks at depths of 2,900 to 3,600 meters, and Upper Tertiary and Upper Cretaceous sandstones, of US$101.4 million through the end of the first exploratory periods for these blocks, which we expect will occur by November 2015 for the Flamenco at depths of 700 to 2,000 meters. and Isla Norte Blocks and by January 2016 for the Campanario Block, which includes our covering of ENAP’s investment commitment which corresponds Our geosciences team continues to identify and develop an attractive to its working interest in the blocks. In the first quarter of 2012, we began inventory of prospects and drilling opportunities for both exploration and 3D seismic operations in the Flamenco Block. As of March 2014, 8 wells have development in the Fell Block, and we expect to continue our comprehensive been drilled and 1,500 sq. km of 3D seismic have been carried out over the drilling program in the Fell Block in the coming years. The recent oil three blocks; which represent the total 3D seismic program commitment. discoveries in the Konawentru, Yagan, Yagán Norte , Copihue and Guanaco fields have opened up new oil and gas potential in the Fell Block. An Exploration in the Tierra del Fuego province in the Magallanes Basin dates important discovery during 2011 was the Konawentru 1 well, which we back to the 1940s, when the first surface exploration focused on obtaining initially tested to have in excess of 2,000 bopd from the Tobífera formation, stratigraphic and structural information. Structural traps with transgressive and which has opened up additional potentially attractive opportunities sandstone reservoirs (Springhill formation) were outlined with refraction (workovers, welldeepenings and new exploration and development wells) seismic lines and, in 1945, oil was discovered. in the Tobífera formation throughout the Fell Block. 76 GeoPark 20F In the specific area of our Tierra del Fuego Blocks, the first wells were drilled in the Flamenco Block. Omeling 1 was completed as an oil productive well 1951, resulting in the discovery of the Sombrero oil and gas field. At the end while Yakamush 1 and Chilco 1 are still waiting for completion. As of April of the 1950s and in the early 1960s, new fields were discovered to the east 2014, we drilled four additional wells in the Flamenco Block, all of them (the Catalina and Cuarto Chorrillo fields) and, following the gathering of were completed as of the date of this annual report, and an seismic reflection data acquisition, additional new fields were discovered and additional well is currently being drilled. existing fields were further developed. During the past decade, geological studies in the Magallanes Basin have focused on stratigraphic analysis, based As of December 31, 2013, we had completed 100% of the committed 570 sq. on 3D and 2D seismic information, the definition and distribution of facies km of 3D seismic surveys. We have also committed to drilling 10 wells during of the deltaic and/or turbidite depositional systems of the Late Cretaceous- the first exploration period under the CEOP governing the Flamenco Block. Tertiary period and the evolution of the oil system in terms of generation/timing/expulsion and trapping. Otway and Tranquilo Blocks We are the operator of the Otway and Tranquilo Blocks. Geologically, our Tierra del Fuego Blocks are located in the south-eastern margin of the Magallanes Basin. The principal producing reservoir is In the Otway Block, as of December 31, 2013, we had a 25% working composed by sandstones in the Springhill formation at depths of 1,800 to interest and our partners were Pluspetrol (25%), Wintershall (25%), IFC (12.5%) 2,300 meters. Additional reservoirs have been discovered and put into and Methanex (12.5%). Our partners withdrew from the joint operating production in the Tierra del fuego Blocks namely Tobífera formation agreement governing the Otway Block in May 2013, and applied to the volcaniclastic rocks at depths of 2,000 to 2,500 meters, and Upper Terciary Chilean Ministry of Energy to assign their rights to us in the Otway Block CEOP and Upper Cretaceous sandstones, at depths of 500 to 1,400 meters. in August 2013. The Ministry of Energy approved the assignment on August 26, 2013, subject to the execution of a deed of assignment of rights Isla Norte Block. We are the operator of, and have a 60% working interest in, containing the as-approved terms. Following the execution of this the Isla Norte Block, which covers approximately 130,200 gross acres (527 sq. assignment deed, we will be the sole participant in the Otway Block CEOP. km). As of March 2014 we had completed 100% of the committed 350 sq. km of 3D seismic surveys. We have also committed to drilling three wells during In 2012, we drilled two wells in the Otway Block, both of which were the first exploration period under the CEOP governing the Isla Norte Block. subsequently plugged and abandoned. Campanario Block. We are the operator of, and have a 50% working interest in, the Campanario Block, which covers approximately 192,200 gross On April 10, 2013, we voluntarily and formally announced to the Chilean Ministry of Energy our decision not to proceed with the second exploratory acres (778 sq. km). As of December 31, 2013, we had completed 100% of period and to terminate the exploratory phase under the Otway Block the committed 578 sq. km of 3D seismic surveys. We have also committed CEOP, such that we relinquished all areas of the Otway Block, except for two to drilling eight wells during the first exploration period under the CEOP areas totaling 49,421 gross acres in which we declared the discovery of governing the Campanario Block. We are currently drilling the Primavera Sur 1 well, being the first exploration well of the commitment. hydrocarbons, in the Cabo Negro and Tatiana prospect areas. In the Tranquilo Block, as of December 31, 2013, we had a 29% working Flamenco Block. We are the operator of, and have a 50% working interest in, the Flamenco Block, which covers approximately 143,800 gross acres interest, where our partners were Pluspetrol (29%), Wintershall (25%) and Methanex (17%). Methanex and Wintershall have recently announced its (582 sq. km). In June 2013, we discovered a new oil and gas field in the block decision to exit the Tranquilo Block Consortium. The new ownership in the following the successful testing of the Chercán 1 well, the first well drilled Tranquilo Block is being negotiated among us and Pluspetrol. by us in Tierra del Fuego. We conducted a production test in the Tobífera formation, in which gas flowed at a rate of approximately 4.0 mmcfpd In the Tranquilo Block we completed a seismic program consisting of 163 sq. and oil flowed at rates of approximately 35 bopd. We have completed the km of 3D seismic and 371 sq. km of 2D seismic survey work, and drilled four construction of a flowline to connect this well to existing infrastructure, wells, including the Palos Quemados and Marcou Sur well. The Marcou Sur and the well is currently producing approximately 2,900 mcfpd and 21 bopd well is under evaluation and we discovered gas in the El Salto formation of under a long-term production test. Together with ENAP, we decided to pass the Palos Quemado well. At the Palos Quemados well, we recently completed on to the commercialization phase. We have also completed drilling three a 22-week commercial feasibility test aimed at defining its productive additional wells in 2013, the Omeling 1, Yakamush 1 and Chilco 1 wells in potential. As the test was not conclusive, we were granted permission by GeoPark 20F 77 the Chilean Ministry of Energy to extend the testing period for an additional overriding royalty equal to an estimated 4% of our net revenues for any new six months. In order to continue producing in this well, we will have to discoveries of oil. During 2013, we paid US$7.8 million and accrued US$11.5 declare its commercial viability. million to the previous owners of Winchester pursuant to the Winchester Stock Purchase Agreement. On January 17, 2013, we formally announced to the Chilean Ministry of Energy our decision not to proceed with the second exploratory period and Our interests in Colombia include working interests and economic interests. to terminate the exploratory phase of the Tranquilo Block CEOP. “Working interests” are direct participation interests granted to us pursuant Subsequently, we relinquished all areas of the Tranquilo Block, except for a to an E&P Contract with the ANH, whereas “economic interests” are indirect remaining area of 92,417 gross acres, for the exploitation of the Renoval, participation interests in the net revenues from a given block based on Marcou Sur, Estancia Maria Antonieta and Palos Quemados Fields, which we bilateral agreements with the concessionaires. have identified as the areas with the most potential for prospects in the block. The map below shows the location of the blocks in Colombia in which we have working and/or economic interests. As of December 31, 2013, we had completed our minimum work 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 C A R I B B E A N S E A 270 sq. km of 3D seismic and 127 km of 2D seismic survey work. P A N A M A Cerrito Llanos 17 + Yamú Arrendajo P A C I F I C O C E A N Abanico V E N E Z U E L A Jagüeyes La Cuerva Llanos 62 Llanos 32 Llanos 34 C O L O M B I A B R A Z I L E C U A D O R P E R U (1) The PN-T-597 block is subject to an injunction and our bid for the concession has been suspended. Operations in Colombia In the first quarter of 2012, we acquired Winchester, Luna and Cuerva, three privately-held E&P companies operating in Colombia. We closed the acquisitions of Winchester and Luna in February 2012 and the acquisition of Cuerva in March 2012. We acquired Winchester, Luna and Cuerva for a total consideration of US$105.0 million, adjusted for working capital. Additionally, in December 2012, LGI agreed to acquire a 20% equity interest in GeoPark Colombia for a total consideration of US$20.1 million, composed 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.” Our Colombian acquisitions gave us access to 574,979 of gross exploratory and productive acres across 10 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 6,962 boepd in Colombia in 2013. According to the D&M Reserves Report, as of December 31, 2013, the blocks in Colombia in which we have a working interest had 9.4 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 hydrocarbons discovered by exploration wells drilled after October 25, 2011. These payments involve both an earnings-based measure and an 78 GeoPark 20F Gross acres (thousand acres) Working interest(1) Net proved reserves Production Partners(2) Operator (mmboe)(3) (boepd) Basin Concession expiration year Exploration: 2014 The table summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2013. Block La Cuerva Llanos 34 Llanos 62 Yamú Llanos 17 Llanos 32 47.8 100.0% — GeoPark RIL-Parex; 82.2 45.0% Verano Energy GeoPark 44.0 11.2 100.0% 54.5/ (4)75.0% 108.8 (5)36.8% 100.3 (6)0% — — GeoPark GeoPark RIL- Parex RIL-Parex APCO; Verano Energy Verano Energy Jagu(cid:0) eyes 3432A 61.0 5.0% Columbus Columbus (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, 2013. (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 54.5% interest in the Carupana Field and a 75% 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) We currently have a 10% economic interest in the Llanos 32 Block, although we have applied to the ANH to recognize this as a working interest in the block, and expect to receive the ANH’s authorization in the first half of 2014. (7) 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. 2.6 6.4 — 0.3 0.03 0.06 — 1,962 Llanos Exploitation: 2038 Exploration: 2015 3,469 Llanos Exploitation: 2039 — Llanos 550 Llanos Exploration: 2017 Exploitation: 2041 (7)Exploration: 2013 Production: 2036 Exploration: 2015 49 Llanos Exploitation: 2039 Exploration: 2015 180 Llanos Exploitation: 2039 — Llanos Exploitation: 2038 Exploration: 2014 GeoPark 20F 79 The table summarizes information about the blocks in Colombia in which we and Tigana Sur 1 wells represent our fourth and fifth new oil field discoveries, have economic interests as of and for the year ended December 31, 2013. respectively, in the Llanos 34 Block since 2012. For the year ended December Gross acres (thousand acres) 78.1 32.1 10.2 Economic interest(1) 10% 10% 10% Arrendajo Abanico Cerrito 31, 2013, our average net daily production in the block was 3,469 bopd. During 2013 we completed 250 sq. km of 3D seismic covering the north-west Production part of the block, where our team expects to map new exploration prospects Operator (boepd) Basin to be drilled in 2015. Our partners in the block are Ramshorn International Pacific Pacific Pacific 177 Llanos Limited, or RILParex and Verano Energy Corp., or Verano Energy, who have 95 Magdalena a 45% and 10% interest, respectively. See “—Our operations.” We operate in 9 Catatumbo the block pursuant to an E&P Contract with the ANH. See “—Significant agreements—Colombia—E&P Contracts—Llanos 34 Block E&P Contract.” (1) Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant to a joint operating agreement. La Cuerva Block. We are the operator of, and have a 100% working interest in, the La Cuerva Block, which covers approximately 47,000 gross acres (190 sq. km). Since we acquired an interest in the La Cuerva Block, we have Eastern Llanos Basin: (La Cuerva, Yamú, Llanos 34, Llanos 32, Llanos 62, drilled a total of 15 wells in the block, 10 of which were productive. For the Llanos 17, Jagu(cid:0) eyes 3432A, Arrendajo, Abanico and Cerrito Blocks) The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region year ended December 31, 2013, our average net production at the La Cuerva Block was 1,962 bopd. We operate in the block pursuant to an E&P Contract of Colombia. Two giant fields (Caño Limón and Castilla), three major fields with the ANH. See “—Significant agreements— Colombia—E&P Contracts— (Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had La Cuerva Block E&P Contract.” been discovered. The source rock for the basin is located beneath the east flank of the Eastern Cordillera, as a mixed marine-continental shaly basinal facies of the Gachetá formation. The main reservoirs of the basin are 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 represented by the Paleogene Carbonera and Mirador sandstones. Within the (178 sq. km). As of December 31, 2013, we had undertaken 72.2 sq. km of Cretaceous sequence, several sandstones are also considered to have good 3D seismic surveys within the block. We operate the block pursuant to reservoirs. an E&P Contract with the ANH. 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 (333 sq. 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). km). We acquired an interest in and took operatorship of the block in the Economic rights to certain fields in the Yamú Block have been granted to first quarter of 2012, which at the time had no production, reserves or wells other parties. In May 2013, we successfully drilled and completed the Potrillo drilled on it, and with 210 sq. km of existing 3D seismic on which our 1 well in the block—our third oil field discovery in Colombia—to a total depth team had mapped multiple exploration prospects. We have drilled some of these prospects with positive results. Through 2013, we have drilled 14 of 3,560 meters. The well is producing at a rate of approximately 230 bopd. Surface facilities are already in place, and the crude oil produced from the wells which resulted in five new oil discoveries and 13 new productive wells. well is now being marketed and sold. For the year ended December 31, 2013, These include the Tarotaro 1 exploration well in the Tarotaro Field, which our average net production at the Yamú Block was 550bopd. We operate in we successfully drilled, tested and put into production in June 2013. the block pursuant to an E&P Contract with the ANH. A test conducted on the Tarotaro 1 well resulted in a production rate of approximately 2,239 bopd. Surface facilities are already in place and the crude oil produced from the wells is now being marketed and sold. The Llanos 17 Block. We have a 40% working interest in the Llanos 17 Block, which covers approximately 108,800 gross acres (440 sq. km). Ramshorn Tarotaro Field is the second oil field that we have discovered since our International Limited (“RIL”) -Parex is the operator of, and has a 60% working expansion into Colombia in the first half of 2012. We drilled and tested the interest in, the Llanos 17 Block. Since we acquired a working interest in the Tigana 1 exploration well in the Mirador formation, with production at a rate block, two wells have been drilled in the block, one of which was productive. of approximately 2,126 bopd. In addition, we tested the Guadalupe We maintain our 40% working interest in the Llanos 17 Block pursuant formation, with production at a rate of approximately 1,465 bopd. We also to an E&P Contract with the ANH. However, we expect to apply to the ANH drilled and tested the Tigana Sur 1 well in the Guadalupe formation, which to approve an assignment of 3.2% of our working interest in this block to is currently producing at a rate of approximately 1,598 bopd. The Tigana 1 another party. 80 GeoPark 20F Llanos 32 Block. Verano Energy is the operator of, and has a 50% working interest in, the Llanos 32 Block, which covers approximately 100,300 gross initially entered into with Kappa Resources Colombia Limited (now Pacific), Maral Finance Corporation, Geoproduction Oil & Gas Company of Colombia acres (406 sq. km).Verano Energy’s partners in the block are RIL-Parex and Limitada and Texican Oil PLC. APCO Properties Ltd., or APCO, who have a 30% and a 20% working interest in the block, respectively. Currently, we have a 10% economic interest in the Llanos 32 Block pursuant to a joint operating agreement with Verano Energy. Operations in Brazil On May 14, 2013, we announced the future extension of our footprint into We do not maintain a direct working interest in this block pursuant to an Brazil when the ANP awarded us seven new exploratory licenses in the REC-T E&P Contract with the ANH, but we have applied to the ANH to recognize our 94 and RECT 85 Concessions in the Recôncavo Basin in the State of Bahia and interest in the Llanos 32 Block as a working interest, and expect to receive the the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions ANH’s authorization in the first half of 2014. Since we acquired an interest in in the Potiguar Basin in the State of Rio Grande do Norte, or our Round 11 the Llanos 32 Block, and as of December 31, 2013, five wells have been drilled concessions, collectively covering an area of approximately 54,900 gross in the block, three of which were productive. For the year ended December acres. On September 17, 2013, we entered into seven concession agreements 31, 2013, our average net production in the Llanos 32 Block was 180 bopd. with the ANP for the right to exploit the oil and natural gas in these seven 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 new concessions. For our winning bids on these seven concessions, we committed to invest a minimum of US$15.3 million (including bonuses and estimated work program commitment) during the first three years of the block is Columbus Energy, who maintains a 95% working interest in and is the exploratory period for the concessions, and expect to begin seismic the operator of the Jagu(cid:0) eyes 3432A Block. We maintain a working interest in work in the first half of 2014. These seven new concessions cover an area the Jagu(cid:0) eyes 3432A Block pursuant to an E&P Contract with the ANH. of approximately 54,850 gross acres. Pursuant to ANP requirements, actual exploitation of these new concessions will also depend on obtaining an Arrendajo Block. In December 2005, Great North Energy Colombia Inc. (now Pacific Stratus Energy Corp., or Pacific) and the ANH entered into the Arrendajo environmental license from the respective state environmental agencies. The ANP has also qualified us as a class B operator, meaning that we are Block E&P Contract. Pacific is the operator of, and has a 100% working interest recognized as having met all technical and managerial conditions required in, the Arrendajo Block, which covers approximately 78.1 gross acres. to operate safely in Brazil, both onshore and offshore at water depths of We do not maintain a direct working interest in this block pursuant to an E&P less than 400 meters. As of the date of this annual report, seismic licensing Contract with the ANH, but rather have a 10% economic interest in the net contracts were signed for the Reconcavo basin blocks and for the Potiguar revenues of the Arrendajo Block pursuant to a participating interest agreement basin blocks, which are planned to start during 2014. between us and Great North Energy Colombia Inc. (now Pacific). Additionally, we acquired Rio das Contas from Panoro for a total cash Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Pacific is the consideration of US$140 million (subject to working capital adjustments and further earn-out payments, if any), which closed on March 31, 2014 and gives 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 us a 10% working interest in the BCAM-40 Concession, including the shallow- depth offshore Manatí and Camarão Norte Fields, in the Camamu-Almada working interest in the Abanico Block, but rather have a 10% economic Basin in the State of Bahia. The Manatí Field, which is in the production phase, interest in the net revenues from the block pursuant to a joint operating is operated by Petrobras (with a 35% working interest), the Brazilian national agreement initially entered into with Kappa Resources Colombia Limited company and the largest oil and gas operator in Brazil, in partnership with (now Pacific, who subsequently assigned its participation interest to Cespa de QGEP (with a 45% working interest), and Brasoil (with a 10% working interest). Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & See “—Significant agreements—Brazil—Rio das Contas Quota Purchase Gas), Maral Finance Corporation and Getionar S.A. Agreement.” Some environmental licenses related to operation of the Manatí Cerrito Block. In February of 2002, Ecopetrol and Kappa Resources Colombia Limited (now Pacific) entered into the Cerrito Block association contract. Field production system and natural gas pipeline are expired. However, the operator submitted, timely, the request for renewal of those licenses and as such this operation is not in default as long as the regulator does not state The Cerrito Block covers an area of approximately 10.2 gross acres. Pacific is its final position on the renewal. See “—Health, safety and environmental the operator of, and has a 100% working interest in, the Cerrito Block. We matters—Other regulation of the oil and gas industry—Brazil.” The Camarão do not maintain a direct working interest in the Cerrito Block, but rather have Norte Field is in the development phase and is not yet subject to the a 10% economic interest in the block pursuant to a joint operating agreement environmental licensing requirement. GeoPark 20F 81 Our acquisition of Rio das Contas in Brazil, which closed on March 31, 2014, The map below shows the location of the concessions in Brazil in which provides us with a long-term off-take contract with Petrobras that covers we expect to have working interests as a result of our Brazil Acquisitions. approximately 74% of net proved gas reserves in the Manatí Field, a valuable relationship with Petrobras and an established local platform and presence, with seasoned and experienced geoscience and administrative team to manage the assets and to seek new growth opportunities. 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. Our winning bids B R A Z I L are subject to confirmation of qualification requirements. 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 “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 POT-T-665 REC -T- 85 REC -T- 94 BCAM-40 SEAL-T-268 On September 30, 2013, we entered into a strategic alliance with Tecpetrol to jointly identify, study and potentially acquire upstream oil and gas opportunities in Brazil, with a specific focus on the Parnaíba, Sao Francisco, Recôncavo, Potiguar and Sergipe Alagoas basins. As part of our strategic alliance with Tecpetrol, we expect to enter into an agreement to jointly P A R A G U A Y A R G E N T I N A develop, by assigning to Tecpetrol 50% of our working interest in, the PN T (1) The PN-T-597 block is subject to an injunction and our bid for the 597 concession in the Parnaíba Basin in the State of Maranhão, which we concession has been suspended. See “Item 3. Key Information—D. Risk were awarded by the ANP, subject to confirmation of qualification factors—Risks relating to our business— The PN-T-597 concession is requirements. subject to an injunction and may not close.” 82 GeoPark 20F The following table sets forth information as of December 31, 2013 on our concessions in Brazil in which we have a current or future working interest, including the Round 11 concessions and the Round 12 concessions, and also includes on a pro forma basis information on our recent Rio das Contas acquisition, which closed on March 31, 2014. Gross acres (thousand acres) Working interest(1) Net proved reserves Production Partners Operator (mmboe) (boepd) Basin Concession expiration year Exploration: 2018 7.7 7.7 100% 100% 7.9 100% 7.9 7.9 100% 100% 7.9 100% — — — — — — GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark 7.9 188.7 7.8 251.4 22.8 274.2 100% 100%(5) — —(5) GeoPark GeoPark 100% — GeoPark Petrobras; QGEP; 10% Brasoil Petrobras — — — — — — — — — — — 8.3 — Recôncavo Exploitation: 2045 Exploration: 2018 — Recôncavo Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 Exploration: 2018 Potiguar Exploitation: 2045 — — — — — Potiguar — Parnaíba Sergipe Alagoas — — Exploration: 2018 Exploitation: 2045 —(4) —(4) Camamu- — Almada Exploitation: 2029(2) - 2034(3) 3,580 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(4) Total Brazil BCAM-40 Total Brazil Pro forma (1) Working interest corresponds to the working interests we expect to requirements by the ANP and absence of any legal impediments to signing. hold in such concession, net of any working interests held by other parties See “Item 3. Key Information—Risk factors—Risks relating to our business— in such concession, as a result of our Rio das Contas acquisition and the The PN-T-597 concession is subject to an injunction and may not close.” separate award to us by the ANP of the Round 12 concessions. (5) We expect to jointly develop this concession with Tecpetrol and assign (2) Corresponds to Manatí Field. (3) Corresponds to Camarão Norte Field. 50% of our working interest in this concession to Tecpetrol. See Item 3 - Risk Factors “The PNT- 597 concession is subject to an injunction and may (4) Round 12 concessions are subject to confirmation of qualification not close”. GeoPark 20F 83 BCAM-40 Concession As a result of the Rio das Contas acquisition, we have a 10% working interest 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 in the BCAM-40 Concession, which includes interests in the Manatí Field the signing of the concession agreement in respect of the concessions, to a and the Camarão Norte Field, and which is located in the Camamu-Almada work program to the ANP of R$19.3 million (approximately US$8.5 million, Basin. Petrobras is the operator of, and has a 35% working interest in, the at the March 31, 2014 exchange rate of R$2.263 to US$1.00) during the first BCAM-40 Concession, which covers approximately 22,784 gross acres exploratory period under the concession agreement governing the (92.2 sq. km). In addition to us, Petrobras’ partners in the block are Brasoil concessions, consisting of a R$7.2 million (approximately US$3.2 million, at and QGEP, with 10% and 45% working interests, respectively. Petrobras the March 31, 2014 exchange rate of R$2.263 to US$1.00) bonus payable operates the BCAM-40 Concession pursuant to a concession agreement with to the ANP in the first year of exploration and R$12.1 million (approximately the ANP, executed on August 6, 1998. See “—Significant agreements— US$5.3 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) Brazil—Overview of concession agreements—BCAM-40 Concession as a work program guarantee payable over the course of the three years. Agreement.” In September 2009, Petrobras announced the relinquishment The work program consists on drilling two exploratory wells and 31 sq. km of BCAM- 40’s exploration area within the concession to the ANP, except for of 3D seismic surveys in the REC-T94 Concession and 30 sq. km of 2D seismic the Manatí Field and the Camarão Norte Field. surveys in REC-T 85 Concession. The exploratory phase for these concessions is divided into two exploratory periods, the first of which lasts for three years The Manatí Field is located 65 km south of Salvador, at a 35-meter water and the second of which is non-obligatory and can last for up to two years. depth. 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 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 which are productive and connected to a fixed production platform installed are onshore and located in the Potiguar Basin. As of December 31, 2013, at a depth of 35 meters, located 9 km from the coast of the State of Bahia. according to the ANP, the Potiguar basin was the third largest producer of oil From the platform, the gas flows by sea and land through a 125 km pipeline in Brazil, with 91 fields in production and 11 fields in development stage to the Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to including onshore and offshore. Total production of the above mentioned Petrobras up to a maximum volume as determined in the existing Petrobras fields were 60,402 bopd and 1.460 mmm3 per day of gas. Gas Sales Agreement (as defined below). Rio das Contas is negotiating an amendment to the existing Petrobras Gas Sales Agreement with Petrobras for The POT-T 663, POT-T 664, POT-T 665, POT-T 619 and POT-T 620 the sale of additional volumes from the Manatí Field to Petrobras. Concessions cover a total area of 39,507 gross acres (160 sq. km). The REC-T 94 and REC-T 85 Concessions The REC-T 94 and REC-T 85 Concessions are onshore and located in the concession agreements require us make total investments of R$11.3 million (approximately US$5.0 million at the March 31, 2014 exchange rate of R$2.263 to US$1.00) during the first exploratory period under the concession Recôncavo Basin, which covers an area of approximately 2.7 million gross agreement, with a R$3.0 million (approximately US$1.3 million at the March 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 31, 2014 exchange rate of R$2.263 to US$1.00) bonus payable to the ANP in the first year of exploration and R$8.3 million (approximately US$3.7 million and Pojuca formations, Fluvial sandstones of the Candeias and Marancagalha at the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work formations, and the Fluvio-Eolic sandstones of the Agua Grande and Sergi program guarantee payable over the course of the three years. We have also formations. Reconcavo basin is considered a mature basin. According to the committed to undertaking 222 km of 2D seismic work in the first exploration ANP, as of December 31, 2013, 92 fields are in production or development period for the concession areas, with no well drilling commitment during stage, and production was 43,905 bopd and 2.519 mmm3 per day. this period. The exploratory phase for these concessions is divided into two exploratory periods, the first of which lasts for three years and the second The REC-T 94 and REC-T 85 Concessions cover an area of 7,660 gross acres of which is non-obligatory and can last for up to two years. (31 sq. km) and 7,660 gross acres (31 sq. km), respectively. In connection with our bid to obtain the licenses for these concessions, we have committed to drilling two exploratory wells in the concessions, and to undertaking 31 sq. 84 GeoPark 20F Round 12 Concessions Additionally, on November 28, 2013, the ANP awarded us two new 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 concessions (the PN-T-597 Concession in the Parnaíba Basin in the State of close” and “—D. Risk factors—Risks relating to the countries in which we Maranhão and the SEAL-T-268 Concession in the Sergipe Alagoas Basin operate—Our operations may be adversely affected by political and in the State of Alagoas) in the 12th oil and gas bidding round. Our winning economic circumstances in the countries in which we operate and in which bids are subject to confirmation of qualification requirements. We have we may operate in the future” for more information. committed to invest a minimum of US$4 million (including bonus and work program commitments). For more information, see “Item 3. Key information—D. Risk factors—Risks relating to our business—The PN-T-597 SEAL-T-268 Concession The SEAL-T-268 Concession is located onshore in the Sergipe-Alagoas Basin. concession is subject to an injunction and may not close.” This basin encompasses an area of approximately 10.9 million gross acres PN-T-597 Concession The PN-T-597 Concession is located onshore in the Parnaiba Basin, which (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. Source rock intervals were identified on the Rift (Barra de Ituba and Coqueiro covers an area of approximately 148 million gross acres (600,000 sq. km). Seco Fms) and Prerift sequences (Aracare Fm). Reservoirs are the fluvio-deltaic The basin’s main petroleum system consists of the Devonian Pimenteras Fm and lacustrine sandstones present in the pre-rift and rift intervals (Aracare, source rock with reservoirs of continental to shallow marine sandstones Serraria, Penedo and Maceio Fms). Over the drift sequence, turbiditic of the Poti and Cabeças formations. Intrusive and extrusive magmatic rocks sandstones were deposited, mainly in the offshore part of the basin and are interbedded within the sedimentary column, influencing source rock the cretaceous shale acts as seal. The onshore part of the basin is considered maturation and sometimes acting as seals. mature in terms of hydrocarbon exploration. Parnaiba is a basin with large underexplored areas. As December 31, Sergipe-Alagoas accounts for a production of 44,417 bopd and 4.6 mmm3 2013, the basin had one producing field accounting for the production per day of gas as of December 31th, 2013, according to the ANP. At this of 5.651 mmm3 per day of gas and 144 bopd. Three more fields are in date, there were 55 fields either in production or development stages on development stage. the basin. The PN-T-597 Concession covers an area of 188,667 gross acres (763.5 sq. The SEAL-T-268 Concession covers an area of 7,799 gross acres (31.6 sq. km). km). The offer requires a commitment to the ANP of R$7.7 million GeoPark’s winning offer requires a commitment to the ANP of R$1.6 million (approximately US$3.4 million, at the March 31, 2014 exchange rate of (approximately US$0.7 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) for the first exploratory period. This amount is comprised R$2.263 to US$1.00) for the first exploratory period. This amount is comprised of R$0.9 million (approximately US$0.4 million, at the March 31, 2014 of R$0.14 million (approximately US$0.07 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) bonus payable to the ANP in the first exchange rate of R$2.263 to US$1.00) bonus payable to the ANP in the first year of exploration and R$6.7 million (approximately US$3.0 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work program year of exploration and R$1.5 million (approximately US$0.7 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work program guarantee payable over the course of the four years. Work program is guarantee payable over the course of three years. Work program is equivalent equivalent to 180 km of 2D seismic, with no well drilling committed during to 40 km of 2D seismic, with no well drilling committed during the first the first exploratory period. exploratory period. The exploratory phase for these concessions is divided into two exploratory The exploratory phase for this concession is divided into two exploratory periods. Given that Parnaiba basin is considered as a “new frontier” periods, the first lasting three years, and the second, which is optional, area by the ANP, the first exploratory period lasts four years, and the second can last for up to two years. exploratory period, which is optional, can last for up to two years. GeoPark 20F 85 Operations in Argentina The map below shows the location of the blocks in Argentina in which we have working interests as of December 31, 2013. B O L I V I A P A R A G U A Y B R A Z I L U R U G U A Y Loma Cortaderal Cerro Doña Juana A R G E N T I N A 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, 2013. Block Del Mosquito Cerro Doña Juana(3) Loma Cortaderal(3) Gross acres (thousand acres) Net proved Working interest(1) Operator reserves Production (boepd) (mmboe)(2) Basin Magallanes Expiration concession year 17.3 19.6 28.3 100% 100% 100% GeoPark GeoPark GeoPark — — — 64 Austral — Neuquén Exploitation: 2016 Exploitation: 2017 — Neuquén Exploitation: 2017 (1) Working interest corresponds to the working interests held by our (3) In April 2014, we informed theSecretary of Infrastructure and Energy respective subsidiaries in such block, net of any working interests held by of the Province of Mendoza of our decision to relinquish 100% of the Cerro other parties in each block. (2) As of December 31, 2013. Doña Juana and Loma Cortaderal Concessions to the Mendoza Province. 86 GeoPark 20F As of December 31, 2013, although we had production in our blocks in Oil and natural gas reserves and production Argentina, D&M determined that there were no reserves in these blocks. This was due to the uneconomic status of the reserves, given the proximity to the end of the concessions for these blocks, which does not allow for Overview We have achieved consistent growth in oil and gas reserves from our future capital investment in the blocks. However, if we are able to extend investment activities since 2007, when we began production in the Fell Block. our concessions in Argentina, the assumptions used to make this As of December 31, 2013, D&M reported that on a pro forma basis, our total determination may change in the future. net proved reserves in Brazil (including our Rio das Contas acquisition that closed on March 31, 2014), Chile, Colombia and Argentina were 28.4 mmboe. Del Mosquito Block We are the operator of, and have 100% working interest in, the Del Mosquito Of this total, 8.3mmboe or 29%, 10.7 mmboe, or 38%, 9.4 mmboe, or 33%, were in Brazil, Chile and Colombia, respectively, and we had no net proved Block. We established oil production in the block in 2002 by rehabilitating reserves in Argentina. the abandoned Del Mosquito Field and subsequently discovered the Del Mosquito Norte field. We are evaluating potential drilling opportunities The following table summarizes our net proved reserves in Chile, Colombia on the Del Mosquito Block and the option of bringing a partner into the and Argentina as of December 31, 2013 and also includes on a pro forma project to increase investment activity. For the year ended December 31, basis information related to our Rio das Contas acquisition, which closed on 2013, our average daily production at the Del Mosquito Block was 64 boepd. March 31, 2014. The Del Mosquito Block covers an area of approximately 17,313 gross acres (70 sq. km), and is located in the Magallanes Austral Basin in southern Argentina. According to the Secretariat of Energy (Secretaría de Energía) in Argentina, Chile or the Argentine Secretary of Energy, for the year ended December 31, 2013, Colombia the Magallanes Austral Basin produced approximately 4.6% of Argentina’s Argentina total oil production and approximately 25.2% of its total gas production. Cerro Doña Juana and Loma Cortaderal Blocks The Cerro Doña Juana and Loma Cortaderal Blocks cover areas of Total Brazil(2) Pro forma total Total net proved reserves (mmboe)(1) 10.7 9.4 — 20.1 8.3 28.4 Gas (bcf) 32.2 0.0 — 32.2 48.8 80.9 % Oil 50% 100% — 74% 2% 53% Oil (mmbbl) 5.4 9.4 — 14.8 0.2 15.0 approximately 28,300 (115 sq. km) and 19,600 (79 sq. km) gross acres, (1) We calculate one barrel of oil equivalent as six mcf of natural gas. respectively. (2) Reflects our Rio das Contas acquisition. As of December 31, 2013 we were the operator of, and have a 100% working interest in, each of the Cerro Doña Juana and Loma Cortaderal Blocks. Neither the Cerro Doña Juana nor the Loma Cortaderal Block is currently in production. In April 2014, we informed the Secretary of Infrastructure and Energy of the Province of Mendoza of our decision to relinquish 100% of the Cerro Doña Juana and Loma Cortaderal Concessions to the Mendoza Province. Neither the Cerro Doña Juana nor the Loma Cortaderal are currently in production or have any associated reserves. GeoPark 20F 87 Our reserves The following table sets forth our oil and natural gas net proved reserves and management and acquisition and divestiture opportunities evaluation. See “Item 6. Directors, Senior Management and Employees—A. Directors as of December 31, 2013, which is based on the D&M Reserves Report. and senior management.” In addition, it includes on a pro forma basis information on our Rio das Contas acquisition, which closed on March 31, 2014. In order to ensure the quality and consistency of our reserves estimates and Oil Natural gas (mmbbl) (bcf) Net proved developed - Chile - Colombia - Argentina Total net proved developed - Brazil(2) Total net proved developed Pro forma Net proved undeveloped - Chile - Colombia - Argentina Total net proved undeveloped - Brazil(2) Total net proved 2.2 3.3 — 5.5 0.1 5.6 3.1 6.2 — 9.3 0.1 undeveloped Pro forma Total net proved Total net proved Pro forma 9.4 14.8 15.0 10.0 — — 10.0 28.8 38.8 22.1 — — 22.1 20.0 42.1 32.1 80.9 reserves disclosures, we maintain and comply with a reserves process that Net proved reserves satisfies the following key control objectives: As of December 31, 2013 • estimates are prepared using generally accepted practices and Total net proved reserves (mmboe)(1) 3.9 3.3 — 7.2 4.9 methodologies; • estimates are prepared objectively and free of bias; • estimates and changes therein are prepared on a timely basis; % Oil • estimates and changes therein are properly supported and approved; and • estimates and related disclosures are prepared in accordance with 57% regulatory requirements. 100% — Throughout each fiscal year, our technical team meets with Independent 89% 2% Qualified Reserves Engineers, who are provided with full access to complete and accurate information pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally- 12.1 46% generated reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free of preparer 6.8 6.2 — 13.0 3.4 16.3 20.1 28.4 46% and management bias. 100% — Recognizing that reserves estimates are based on interpretations and 72% 2% 57% 74% 53% judgments, differences between the proved reserves estimates prepared by us and those prepared by an Independent Qualified Reserves Engineer of 10% or less, in aggregate, are considered to be within the range of reasonable differences. Differences greater than 10% must be resolved in the technical meetings. Once differences are resolved, the independent Qualified Reserves Engineer sends a preliminary copy of the reserves report to members of our senior management, who act as a Reserves Review Committee. Our Chief Executive Officer, Chief Financial Officer, Director of Development Geology and Director of Exploration, form this committee. Independent reserves engineers Pro forma reserves estimates as of December 31, 2013 for Brazil, Chile, Colombia and Argentina included in this annual report are based on the (1) We calculate one barrel of oil equivalent as six mcf of natural gas. (2) Reflects our Rio das Contas acquisition. Internal controls over reserves estimation process We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers D&M Reserves Report, completed on March 19, 2014 and effective as to ensure the integrity, accuracy and timeliness of data furnished to of December 31, 2013. The D&M Reserves Report, a copy of which has our independent reserves engineers in their estimation process and who been filed as an exhibit to this annual report, was prepared in accordance have knowledge of the specific properties under evaluation. with SEC rules, regulations, definitions and guidelines at our request in order to estimate reserves and for the areas and period indicated therein. Our Director of Development Geology, Carlos Alberto Murut, is primarily responsible for overseeing the preparation of our reserves estimates and for D&M, a Delaware corporation with offices in Dallas, Houston, Calgary, the internal control over our reserves estimation. He has more than 30 Moscow and Algiers, has been providing consulting services to the years of industry experience as an E&P geologist, with broad experience in oil and gas industry for more than 75 years. The firm has more than 150 reserves assessment, field development, exploration portfolio generation professionals, including engineers, geologists, geophysicists, petrophysicists 88 GeoPark 20F and economists that are engaged in the appraisal of oil and gas properties, royalties, development and environmental permitting and concession terms, the evaluation of hydrocarbon and other mineral prospects, basin may require revision of such estimates. Our operations may also be affected evaluations, comprehensive field studies and equity studies related to the by unanticipated changes in regulations concerning the oil and gas industry domestic and international energy industry. D&M restricts its activities in the countries in which we operate, which may impact our ability to exclusively to consultation and does not accept contingency fees, nor does recover the estimated reserves. Accordingly, oil and natural gas quantities it own operating interests in any oil, gas or mineral properties, or securities ultimately recovered will vary from reserves estimates. or notes 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 D&M did not independently verify the accuracy and completeness of time at which contracts providing the right to operate expire, unless information and data furnished by us with respect to ownership interests, evidence indicates that renewal is reasonably certain, regardless of whether oil and gas production, well test data, historical costs of operation and deterministic or probabilistic methods are used for the estimation. development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in The project to extract the hydrocarbons must have commenced or the the course of the examination something came to the attention of D&M that operator must be reasonably certain that it will commence the project within brought into question the validity or sufficiency of any such information a reasonable time. The term “reasonable certainty” implies a high degree or data, D&M did not rely on such information or data until it had satisfactorily of confidence that the quantities of oil and/or natural gas actually recovered resolved its questions relating thereto or had independently verified such will equal or exceed the estimate. Reasonable certainty can be established information or data. D&M independently prepared reserves estimates to using techniques that have been proved effective by actual production conform to the guidelines of the SEC, including the criteria of “reasonable from projects in the same reservoir or an analogous reservoir or by other certainty,” as it pertains to expectations about the recoverability of reserves evidence using reliable technology that establishes reasonable certainty. in future years, under existing economic and operating conditions, consistent Reliable technology is a grouping of one or more technologies (including with the definition in Rule 4-10(a)(2) of Regulation S-X. D&M issued the computational methods) that have been field tested and have been D&M Reserves Report based upon its evaluation. D&M’s primary economic demonstrated to provide reasonably certain results with consistency and assumptions in estimates included oil and gas sales prices determined repeatability in the formation being evaluated or in an analogous formation. according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us. The There are various generally accepted methodologies for estimating reserves assumptions, data, methods and procedures used, including the percentage of our total reserves reviewed in connection with the preparation of the including volumetrics, decline analysis, material balance, simulation models and analogies. Estimates may be prepared using either deterministic D&M Reserves Report were appropriate for the purpose served by such (single estimate) or probabilistic (range of possible outcomes and probability report, and D&M used all methods and procedures as it considered necessary of occurrence) methods. The particular method chosen should be based under the circumstances to prepare such reports. on the evaluator’s professional judgment as being the most appropriate, given the geological nature of the property, the extent of its operating history However, uncertainties are inherent in estimating quantities of reserves, and the quality of available information. It may be appropriate to employ including many factors beyond our and our independent reserves engineers’ several methods in reaching an estimate for the property. control. Reserves engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact Estimates must be prepared using all available information (open and manner, and the accuracy of any reserves estimate is a function of the quality cased hole logs, core analyses, geologic maps, seismic interpretation, of available data and its interpretation. As a result, estimates by different production/injection data and pressure test analysis). Supporting data, such engineers often vary, sometimes significantly. In addition, physical factors as working interest, royalties and operating costs, must be maintained and such as the results of drilling, testing and production subsequent to the updated when such information changes materially. date of an estimate, economic factors such as changes in product prices or development and production expenses, and regulatory factors, such as GeoPark 20F 89 Proved undeveloped reserves As of December 31, 2013, excluding reserves from Rio das Contas, we had million in capital expenditures to convert such proved undeveloped reserves to proved developed reserves, of which approximately US$56.3 million and 13.0 mmboe in proved undeveloped reserves, an increase of 2.4 mmboe, US$33.8 million were made in Chile and Colombia, respectively. Giving effect or 23%, over our December 31, 2012 proved undeveloped reserves of 10.6 to our recent Rio das Contas acquisition, as of December 31, 2013 we mmboe. The increase in proved undeveloped oil reserves consisted of 4.8 had 16.4 mmboe in proved undeveloped reserves, of which 3.4 mmboe mmboe, partially offset by 2.4 mmboe of revisions principally resulting from corresponds to Rio das Contas. 2.3 mmboe of proved undeveloped reserves converted to proved developed. Of our 13.0 mmboe of net proved undeveloped reserves, 6.8 mmboe, 6.2 Production, revenues and price history The following table sets forth certain information on our production of mmboe and 0 mmboe, or 52%, 48% and 0%, were located in Chile, Colombia oil and natural gas in Chile, Colombia and Argentina for each of the years and Argentina, respectively. During 2013, we incurred approximately US$90.1 ended December 31, 2013, 2012 and 2011: Total Chile Colombia Argentina GeoPark(4) 2013 Colom- 2012 Total Average daily production(1) As of December 31, 2011 Total Chile bia(2) Argentina GeoPark Chile Colombia Argentina GeoPark Oil production Average crude oil production (bopd) 4,581 6,482 50 11,113 4,013 3,431 48 7,491 2,441 Average sales price of crude oil (US$/bbl)(4) Natural gas production Average natural gas 84.3 80.3 70.3 82.0 85.42 97.15 67.8 90.5 83.8 production (mcfpd) 14,283 52 84 14,419 22,663 56 84 22,804 30,419 5.0 4.18 1.1 5.0 4.04 4.18 1.1 4.0 3.9 4.0 8.3 12.2 26.5 19.0 10.7 34.0 (6.7) 16.8 Other (US$/boe) 2.9 4.1 3.5 2.5 4.0 2.9 Average production cost (US$/boe)(3) Average depreciation 15.1 30.6 12.3 22.5 13.2 38.1 (US$/boe) 11.5 16.6 2.5 13.9 9.9 20.4 142.1 13.4 9.1 Average production cost (US$/boe) 26.6 47.2 14.8 36.4 23.1 58.4 143.0 33.1 19.4 8.6 1.7 7.6 0.9 19.7 10.3 Average sales price of natural gas (US$/mcf)(4) Oil and gas production cost Average operating cost (US$/boe) Average royalties and — — — — — — — — — 68 2,508 59.4 83.8 87 30,506 1.1 3.9 6.8 7.0 8.6 1.7 13.7 10.3 29.6 9.3 43.3 19.7 (1) We present production figures net of interests due to others, but Winchester, Luna and Cuerva prior to their acquisition by us. before deduction of royalties, as we believe that net production before (3) Calculated pursuant to FASB ASC 932. royalties is more appropriate in light of our foreign operations and the (4) Averaged realized sales price for oil does not include our Argentine attendant royalty regimes. blocks because our Argentine operations were not material during such (2) We acquired Winchester and Luna in February 2012 and Cuerva periods. Averaged realized sales price for gas does not include our Argentine in March12. Production figures do not include, for 2012, production for and Colombian blocks because our gas operations in those countries were not material during such period. 90 GeoPark 20F For the year ended December 31, 2013, information on our Rio das Contas acquisition, which we closed in March 31, 2014, was as follows: As of Dec 31, 2013 Oil production Average crude oil production (bopd) Average sales price of crude oil (US$/bbl) Natural gas production Average natural gas production (mcfpd) Average sales price of natural gas (US$/mcf)(4) Oil and gas production cost Average operating cost (US$/boe) Average royalties and Other (US$/boe) Average production cost (US$/boe)(3) Average depreciation (US$/boe) Average production cost (US$/boe) Brazil 60 108.3 21,120 6.4 8.3 3.8 12.1 14.9 27.0 Drilling activities The following table sets forth the exploratory wells we drilled as operators in Chile, Colombia and Argentina during the years ended December 31, 2013, 2012 and 2011. Productive Gross Net Dry Gross Net Total Gross Net 2013 2012 Exploratory wells(1) As of December 31, 2011 Chile Colombia Argentina Chile Colombia(2) Argentina Chile Colombia Argentina 7.0 4.8 3.0 1.5 10.0 6.3 9.0 6.0 1.0 1.0 10.0 7.0 — — — — — — 8.0 8.0 6.0 4.5 14.0 12.5 4.0 2.4 3.0 2.5 7.0 4.9 — — — — — — 7.0 7.0 7.0 7.0 14.0 14.0 — — — — — — 1.0 1.0 — — 1.0 1.0 (1) Includes appraisal wells. (2) We acquired Winchester and Luna in February 2012 and Cuerva in March12. Figures do not include, for 2012, exploration activities for Winchester, Luna and Cuerva prior to their acquisition by us. GeoPark 20F 91 The following table sets forth the development wells we drilled in Chile, Colombia and Argentina during the years ended December 31, 2013, 2012 and 2011. Productive Gross Net Dry Gross Net Total Gross Net 2013 2012 Development wells As of December 31, 2011 Chile Colombia Argentina Chile Colombia(1) Argentina Chile Colombia Argentina 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 — — — — — — 8.0 8.0 — — 8.0 8.0 — — — — — — — — — — — — (1) We acquired Winchester and Luna in February 2012 and Cuerva in March For the year ended December 31, 2013, total developed acreage in Brazil was 2012. Figures do not include, for 2012, exploration activities for Winchester, 18.7 thousand acres (gross) and 1.9 thousand acres (net). Total undeveloped Luna and Cuerva prior to their acquisition by us. acreage was 4.1 thousand acres (gross) and 0.4 thousand acres (net). Total developed and undeveloped acreage was 22.8 thousand acres (gross) and 2.3 For the year ended December 31, 2013 there were no exploratory wells drilled thousand acres (net). in our Rio das Contas acquisition, which we closed on March 31, 2014. 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, 2014. Productive wells consist of producing wells and wells capable and net developed and undeveloped acreage in Chile, Colombia and of producing, including natural gas wells awaiting pipeline connections Argentina as of December 31, 2013. Total developed acreage Gross Net Total undeveloped acreage Gross Net Total developed and undeveloped acreage Gross Net Acreage(1) Argentina Colombia (in thousands of acres) 3.3 2.6 2.4 1.3 5.7 3.9 2.0 2.0 - - 2.0 2.0 Chile 14.5 14.5 7.4 7.4 21.9 21.9 to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells. Oil wells Gross Net Gas wells Gross Net Chile Colombia(2) Productive wells(1) Argentina 46.0 45.0 27.0 25.8 72.0 36.5 — — 5.0 5.0 — — (1) Includes wells drilled by other operators, prior to our commencing operations, and wells drilled in blocks in which we are not the operator. (1) Defined as acreage assignable to productive wells. Net acreage based on (2) We acquired Winchester and Luna in February 2012 and Cuerva in our working interest. March2012. Figures include wells drilled by Winchester, Luna and Cuerva prior to their acquisition by us. 92 GeoPark 20F For the year ended December 31, 2013, there were 6.0 gross and 0.6 net productive gas wells in our Rio das Contas acquisition, which we closed on March 31, 2014. Present activities The following table shows the number of wells in Chile, Colombia 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, 2014. Wells in process of being drilled or in active completion(1) Argentina Colombia Chile Wells suspended or waiting on completion(2) Argentina Colombia Chile Oil wells Gross Net Gas wells Gross Net — — — — 1.0 0.5 — — — — — — — — 1.0 0.3 2.0 0.9 — — — — — — (1) We consider wells to be in active completion when we have begun until the expiration of the Fell Block CEOP, which is the earlier of August procedures used in finishing and equipping them for production. 24, 2032 or the date on which we cease exploitation of hydrocarbons in the (2) We consider wells to be waiting on completion when we have completed Fell Block. Commercial conditions of the amended contract are similar to drilling in such wells but have not yet begun to perform testing procedures. the previous one in effect, however the price will now be related to Ice Brent For the year ended December 31, 2013, there were no wells in process of some terms of the contract have improved for us, including changes in the being drilled or in active completion stages, nor were there any wells calculation of certain discounts, such as discounts for mercury content. Crude Futures on the London Intercontinental Exchange. In addition, suspended or waiting on completion in our Rio das Contas acquisition, which we closed on March 31, 2014. Marketing and delivery commitments Chile Our customer base in Chile is limited in number and primarily consists of We deliver the oil we produce in the Fell Block to ENAP at the Gregorio Terminal, where ENAP assumes responsibility for the oil. ENAP owns two refineries in Chile in the north central part of the country and must ship any oil from the Gregorio Terminal to these refineries unless it is consumed locally. ENAP and Methanex. For the year ended December 31, 2013, we sold 100% Under the Methanex Gas Supply Agreement, Methanex has committed to of our oil production in Chile to ENAP and 99% of our gas production to purchasing, and we have committed to selling, all of the gas that we Methanex, with sales to ENAP and Methanex accounting for 39.8% and 6.7%, produce in the Fell Block (subject to certain exceptions, including reasonable respectively, of our revenues in the same period. quantities required to maintain our operations and quantities that we might be required to pay in kind to Chile), with a minimum volume commitment Under our oil sales agreement with ENAP, or the ENAP Oil Sales Agreement, which is defined by us on an annual basis. The agreement contains monthly ENAP has committed to purchase our oil production in the Fell Block, but DOP obligations, which require us to deliver in a given month the minimum only in the amounts that we produce, and with the only limitation being gas committed for that month or pay a deficiency penalty to Methanex, storage capacity at the Gregorio Terminal. The sales contract with ENAP is with a threshold of 90% of the committed quantities of gas. The agreement commonly revised every two years to reflect changes in the global oil market also contains monthly TOP obligations, which apply when our committed and to adjust to logistics costs of ENAP in the Gregorio oil terminal. The volume for a given month exceeds 35.3 mcfpd, and require Methanex to take current agreement has been recently executed, with an initial term of 1 year, in such month the minimum gas volume committed for such period or face until March 2015, and it will be automatically extended for periods of 1 year higher TOP obligations in later months, with a threshold of 90% of the GeoPark 20F 93 committed quantities. These DOP and TOP obligations are subject to make- up provisions without penalty, for any delivery or off-take deficiencies Colombia Our production in Colombia consists almost exclusively of oil. Our oil sales accrued, in the three months following the month where delivery or off-take agreements are generally for a fixed term, with a maximum length of one requirements were not met. We failed to meet this adjusted volume for each year. They do not commit the parties to a minimum volume, and are subject of the months of April through December of 2012, such that we accrued to the ability of either party to receive or deliver production. The contracts US$1.7 million in DOP payments owed to Methanex under the Methanex Gas generally provide that they can be renewed by mutual written agreement, Supply Agreement, all of which had been paid as of September 30, 2013. and all allow for early termination by either party with advanced notice and In April 2013, Methanex idled its plant, but committed to purchasing without penalty. from us the minimum committed gas volumes under the Methanex Gas The delivery points for our production range from the well-head to the port Supply Agreement during the time the plant was idle. The plant resumed of export (Coveñas), depending on the client. If sales are made via pipeline, operations on September 23, 2013. The same condition is expected in the delivery point is usually the pipeline injection point, whereas for direct 2014, as ENAP will require additional gas beyond its own production to export sales, the most frequent delivery point is the well-head. In Colombia, supply residential consumption. We also expect that Methanex will require the restrictions to access pipeline networks, especially for mid to heavy additional deliveries to restart its plant after the winter months, beginning crudes, have forced the market to access different ways of transport and in September 2014. commercialization, reducing our dependency on pipeline infrastructure significantly. For the year ended December 31, 2013, we sold approximately On August 30, 2013, we signed an amendment to the Methanex Gas 66% of our production directly at the well-head and approximately 30% Supply Agreement, pursuant to which Methanex has committed, for a period to the major oil companies that own capacity in the pipelines. In the first of six months beginning September 15, 2013, to purchase an increased quarter of 2014, access to the pipeline network has improved upon the volume, a total amount of 400,000 SCM/d per month (subject to reduction commencement of the Bicentenario pipeline, which added transportation for deliveries above 200,000 SCM/d to Methanex or ENAP made between capacity of 100,000 bopd and also open up additional supply opportunities April 29 and September 15, 2013), at an additional price per month of involving reduced trucking costs. Since we do not own capacity in, or US$1.50 per mmbtu for volumes in excess of 180,000 SCM/d, or an additional have access to, the oil transportation pipelines in Colombia or have any price per month of US$2.00 per mmbtu in any month in which we commit other assets for the transportation of our commodities, we use third parties to deliver at least 500,000 SCM/d (subject to certain exceptions based to transport our production by pipeline or truck. on methanol prices). The amendment also provides for temporary DOP and TOP thresholds of 100% and 50%, respectively. The amendment has been The price of the oil that we sell under these agreements is based on a extended until April 30 2014. Therefore, we are currently committed to market reference price (Brent, WTI or Vasconia), adjusted for certain providing Methanex with a monthly volume of gas of 0.424 bcf until April marketing and quality discounts based on, among other things, API, viscosity, 30, 2014. As of the date of this annual report, we have fulfilled the delivery sulphur and water content, as well as for certain transportation costs volume commitment. (including pipeline costs and trucking costs). We gather the gas we produce in several wells through our own flow lines For the year ended December 31, 2013, we made 52.5% of our oil sales to and inject it into several gas pipelines owned by ENAP. The transportation Gunvor, 20.9% to Hocol and 9.8% to Perenco, with Gunvor accounting of the gas we sell to Methanex through these pipelines is pursuant to a for 27.8%, Hocol 11.1% and Perenco 5.2% of our overall revenues for the private contract between Methanex and ENAP. We do not own any principal same period. If we were to lose any one of our key customers, the loss could natural gas pipelines for the transportation of natural gas. temporarily delay production and sale of our oil in the corresponding block. However, we believe we could identify a substitute customer to purchase If we were to lose any one of our key customers in Chile, the loss could the impacted production volumes. temporarily delay production and sale of our oil and gas in Chile. For a discussion of the risks associated with the loss of key customers, see “Item 3. Key Information—D. Risk factors—Risks relating to our business— Brazil Our production in Brazil consists of natural gas and condensate oil. Natural We sell all of our natural gas in Chile to a single customer, who has in the gas production is sold through a long-term, extendable agreement with past temporarily idled its principal facility” and “—We derive a significant Petrobras, which provides for the delivery and transportation of the gas portion of our revenues from sales to a few key customers.” produced in the Manatí Field to the EVF gas treatment plant in the State of 94 GeoPark 20F Bahia. The contract is in effect until delivery of the maximum committed Significant agreements volume or June 2030, whichever occurs first. The contract allows for sales above the maximum committed volume if mutually agreed by both seller and buyer. We are currently negotiating an amendment to the contract in order to provide for the purchase and sale of additional volumes, pending the Chile CEOPs We have entered into six CEOPs with Chile, one for each of the blocks in closing of the gas compression facility. The price for the gas is fixed in reais which we operate, which grant us the right to explore and exploit and is adjusted annually in accordance with the Brazilian inflation index. hydrocarbons in these blocks, determine our working interests in the blocks and appoint the operator of the blocks. These CEOPs are divided into The Manatí Field is developed via a PMNT-1 production platform, which is two phases: (1) an exploration phase, which is divided into two or more connected to the Estação Vandemir Ferreira, or EVF, gas treatment plant exploration periods, and which begins on the effectiveness date of through an offshore and onshore pipeline with a capacity of 335.5 mmcfpd the relevant CEOP, and (2) an exploitation phase, which is determined on a (9.5 mm3 per day). The existing pipeline connects the field’s platform to perfield basis, commencing on the date we declare a field to be commercially the EVF gas treatment plant, which is owned by the field’s current concession viable and ending with the term of the relevant CEOP. In order to transition holders. The BCAM-40 Concession, which includes the Manatí Field, from the exploration phase to an exploitation phase, we must declare a also benefits from the advantages of Petrobras’s size. As the largest onshore discovery of hydrocarbons to the Ministry of Energy. This is a unilateral and offshore operator in Brazil, Petrobras has the ability to mobilize the declaration, which grants us the right to test a field for a limited period of resources necessary to support its activities in the concession. time for commercial viability. If the field proves commercially viable, we must make a further unilateral declaration to the Ministry of Energy. In the The condensate produced in the Manatí Field is subject to a condensate exploration phase, we are obligated to fulfill a minimum work commitment, purchase agreement with Petrobras, pursuant to which Petrobras has which generally includes the drilling of wells, the performance of 2D or committed to purchase all of our condensate production in the Manatí 3D seismic surveys, minimum capital commitments and guaranties or letters Field, but only in the amounts that we produce, without any minimum or of credit, as set forth in the relevant CEOP. We also have relinquishment maximum deliverable commitment from us. The agreement is valid obligations at the end of each period in the exploration phase in respect through December 31, 2015, but can be renewed upon an amendment of those areas in which we have not made a declaration of discovery. signed by Petrobras and the seller. We can also voluntarily relinquish areas in which we have not declared discoveries of hydrocarbons at any time, at no cost to us. In the exploitation If the agreements with Petrobras were terminated, this could temporarily phase, we generally do not face formal work commitments, other than delay production and sale of our natural gas and condensate oil in Brazil, the development plans we file with the Chilean Ministry of Energy for each and could have a detrimental effect on our ability to find substitute field declared to be commercially viable. customers to purchase our production volumes. Argentina In Argentina, we sell substantially all of our oil production to Oil Our CEOPs provide us with the right to receive a monthly remuneration from Chile, payable in petroleum and gas, based either on the amount of petroleum and gas production per field or according to Recovery Factor, Combustibles, but because the volume we produce in Argentina is small which considers the ratio of hydrocarbon sales to total cost of production and the sale price is fixed at the moment when all other producers have (capital expenditures plus operating expenses). Pursuant to Chilean delivered their product to the Punta Loyola terminal, from which we sell our law, the rights contained in a CEOP cannot be modified without consent crude, we do not sell our oil to Oil Combustibles at a predetermined formula of the parties. or price, but rather on the basis of on-call contracts based on demand. We have the ability to store and process the oil we produce in Argentina which vary depending upon the phase of the CEOP. During the exploration ourselves, and do not have material contracts with third parties for phase, Chile may terminate a CEOP in circumstances including a failure such services. We enter into ad hoc contracts with local companies for the by us to comply with minimum work commitments at the termination of transportation of crude from fields in the Del Mosquito Block to the Punta any exploration period, or a failure to communicate our intention to proceed Our CEOPs are subject to early termination in certain circumstances, Loyola terminal. with the next exploration period 30 days prior to its termination, a failure to provide the Chilean Ministry of Energy the performance bonds required under the CEOP, a voluntary relinquishment by us of all areas under the CEOP GeoPark 20F 95 or a failure by us to meet the requirements to enter into the exploitation into various exploration phases and (2) the exploitation period, determined phase upon the termination of the exploration phase. In the exploitation on a per-area basis and beginning on the date we declare an area to be phase, Chile may terminate a CEOP if we stop performing any of the commercially viable. Commercial viability is determined upon the completion substantial obligations assumed under the CEOP without cause and do of a specified evaluation program or as otherwise agreed by the parties not cure such nonperformance pursuant to the terms of the concession, to the relevant E&P Contract. The exploitation period for an area may be following notice of breach from the Chilean Ministry of Energy. Additionally, extended until such time as such area is no longer commercially viable and Chile may terminate the CEOP due to force majeure circumstances (as certain other conditions are met. defined in the relevant CEOP). If Chile terminates a CEOP in the exploitation phase, we must transfer to Chile, free of charge, any productive wells and Pursuant to our E&P Contracts, we are required, as are all oil and gas related facilities, provided that such transfer does not interfere with our companies undertaking exploratory and production activities in Colombia, abandonment obligations and excluding certain pipelines and other assets. to pay a royalty to the Colombian government based on our production Other than as provided in the relevant CEOP, Chile cannot unilaterally of hydrocarbons, as of the time a field begins to produce. Under Law 756 terminate a CEOP without due compensation. See “Item 3. Key Information— of 2002, as modified by Law 1530 of 2012, the royalties we must pay in D. Risk factors—Risks relating to our business—Our contracts in obtaining connection with our production of light and medium oil are calculated on rights to explore and develop oil and natural gas reserves are subject to a field-by-field basis, using the following sliding scale: contractual expiration dates and operating conditions, and our CEOPs, E&P Contracts and concession agreements are subject to early termination in certain circumstances.” Production (mbop) Up to 5,000 Fell Block CEOP. On November 5, 2002, we acquired a percentage of rights and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, 5,000 to 125,000 125,000 to 400,000 and on May 10, 2006, we became the sole owners, with 100% of the rights 400,000 to 600,000 and interest in the Fell Block CEOP. Chile had originally entered into a CEOP Greater than 600,000 for the Fell Block with ENAP and Cordex Petroleum Inc., or Cordex, on April Production Royalty rate 8% 8-20% 20% 20-25% 25% 29, 1997, which had an effective date of August 25, 1997. The Fell Block In the case of natural gas, the royalties are 80% of the rates presented CEOP grants us the exclusive right to explore and exploit hydrocarbons in above for the exploitation of onshore and offshore fields at depths less than the Fell Block and has a term of 35 years, beginning on the effective date. or equal to 304.8 meters, and 60% for the exploitation of offshore fields at The Fell Block CEOP provided for a 14-year exploration period, composed of depths exceeding 304.8 meters. For new discoveries of heavy oil, classified numerous phases that ended in 2011, and an up-to-35-year exploitation as oil with an API equal to or less than 15°, the royalties are 75% of the rates phase for each field. presented above. Additionally, in the event that an exploitation area has produced amounts in excess of an aggregate amount established in the E&P The Fell Block CEOP provides us with a right to receive a monthly retribution from Chile payable in petroleum and gas, based on the following per-field Contract governing such area, the ANH is entitled to receive a “windfall profit,” to be paid periodically, calculated pursuant to such E&P Contract. formula: 95% of the oil produced in the field, for production of up to 5,000 bopd, ring fenced by field, and 97% of gas produced in the field, for In each of the exploration and exploitation periods, we are also obligated production of up to 882.9 mmcfpd. In the event that we exceed these levels to pay the ANH a subsoil use fee. During the exploration period, this fee is of production, our monthly retribution from Chile will decrease based scaled depending on the contracted acreage. During the exploitation period, on a sliding scale set forth under the Fell Block CEOP to a maximum of 50% the fee is assessed on the amount of hydrocarbons produced, multiplied of the oil and 60% of the gas that we produce per field. by a specified dollar amount per barrel of oil produced or thousand cubic Colombia E&P Contracts We have entered into E&P Contracts granting us the right to explore and feet 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 Colombian block as a working interest. These E&P Contracts are generally unilateral termination clauses or termination clauses mandated by Colombian divided into two periods: (1) the exploration period, which may be subdivided law. Anticipated termination declared by the ANH results in the immediate 96 GeoPark 20F enforcement of monetary guaranties against us and may result in an action interest, giving Ramshorn a 55% working interest and us a 45% working for damages by the ANH. Pursuant to Colombian law, if certain conditions are interest in the Llanos 34 Block. met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the Colombian government We are currently in the exploration period of the Llanos 34 Block E&P during a certain period of time. See “Item 3. Key Information—D. Risk factors— Contract. The contract provides for a six-year exploration period, consisting Risks relating to our business—Our contracts in obtaining rights to explore of two three-year phases, which can be extended for up to six additional and develop oil and natural gas reserves are subject to contractual expiration months to allow for the completion of exploration activities. The Llanos 34 dates and operating conditions, and our CEOPs, E&P Contracts and concession Block E&P Contract provides for a 24- year exploitation period for each agreements are subject to early termination in certain circumstances.” commercial area, beginning on the date on which such area is declared 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 commercially viable. The exploitation period may be extended for periods of up to 10 years at a time, until such time as the area is no longer commercially viable and certain conditions are met. We have presented evaluation E&P Contract, we were granted the right to explore and operate, and a 100% programs to the ANH for the Max, Túa and Tarotaro Fields, which expire on working interest in, the La Cuerva Block. September 15, 2014, December 1, 2014, and November 17, 2015, respectively. We are currently in the sixth phase of exploration under the La Cuerva Block Pursuant to the Llanos 34 Block E&P Contract and applicable law, we are E&P Contract. The exploration period has six phases and terminates on July required to pay to the ANH a royalty based on hydrocarbons produced in the 16, 2014. Each exploration period requires a guaranty of 10% of the total Llanos 34 Block. In the Max Field, we pay the ANH a royalty of at least 6.0%, budget for the corresponding exploration period or post-exploration period and in the Túa and Tarotaro Fields, we pay a royalty of at least 8.0%. (such amount must be at least US$100,000 and may not exceed US$3 million). Additionally, we are required to pay a subsoil use fee to the ANH, which, during Production began in the west, southwest and southern areas of the block the exploration period, is scaled depending on the contracted acreage, and on December 13, 2011, February 15, 2012 and April 23, 2012, respectively. which, during the exploitation period, is equivalent to the amount of oil The La Cuerva Block E&P Contract provides for a 24-year exploitation period we produce multiplied by US$0.1162 per bbl or the amount of natural gas we for each area in the La Cuerva Block, beginning from the date such area is produce multiplied by US$0.01162 per mcf. The ANH also has the right to declared commercially viable. receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Llanos 34 Block E&P Contract. The ANH also has an Pursuant to the La Cuerva Block E&P Contract and applicable law, we are additional economic right equivalent to 1% of production, net of royalties. required to pay to the ANH a royalty of at least 8.0% based on hydrocarbons produced, in accordance with the table presented above. Additionally, we are required to pay a subsoil use fee to the ANH, which, during the Winchester and Luna Stock Purchase Agreement Pursuant to the stock purchase agreement entered into on February 10, 2012 exploration period, is scaled depending upon the contracted acreage, and with Darlan S.A., Bonanza Ventures, Inc., Winamac Holdings Inc. and Realstep which, during the exploitation period, is equivalent to the amount of oil we produce multiplied by US$0.1119 per bbl or the amount of natural Overseas Inc., as the Sellers, or the Winchester Stock Purchase Agreement, we agreed to pay the Sellers a total consideration of US$30.0 million, adjusted gas we produce multiplied by US$0.0119 per mcf. The ANH also has the right for working capital. Additionally, under the terms of the Winchester Stock to receive an additional fee when prices for oil or gas, as the case may be, Purchase Agreement, we are obligated to make certain payments to exceed the prices set forth in the La Cuerva Block E&P Contract. the Sellers based on the production and sale of hydrocarbons discovered by Llanos 34 Block E&P Contract. Pursuant to an E&P Contract between Unión Temporal Llanos 34 (a consortium between Ramshorn and Winchester) and exploration wells drilled after October 25, 2011. The agreement provides that we make a quarterly payment to the Sellers in an amount equal to 14% of adjusted revenue (as defined under the agreement) from any new the ANH that became effective as of March 13, 2009, or the Llanos 34 Block discoveries of oil, up to the maximum earn-out amount of US$35.0 million E&P Contract, Unión Temporal Llanos 34 was granted the right to explore (net of Colombian taxes). Once the maximum earn-out amount is reached, and operate the Llanos 34 Block, and we and Ramshorn were granted a 40% we will pay the Sellers quarterly overriding royalties in an amount equal and a 60% working interest, respectively, in the Llanos 34 Block. We were to 4% of our net revenues from any new discoveries of oil. For the year ended also granted the right to operate the Llanos 34 Block. On December 16, 2009, December 31, 2013, we paid US$7.8 million and accrued US$11.5 million we entered into a joint operating agreement with Ramshorn and P1 Energy with regards to this agreement. in respect of our operations in the block. On August 31, 2012, the ANH approved the assignment by Ramshorn to us of an additional 5% working GeoPark 20F 97 Cuerva purchase and sale agreement Pursuant to the purchase and sale agreement dated March 26, 2012 between concession area or the declaration of commercial viability with respect to a given area), while the development and production phase, which begins for Hupecol Cuerva Holdings LLC, as the Seller, and us, we agreed to pay to each field on the date a declaration of commercial viability is submitted the Seller a total consideration of US$75 million, adjusted for working capital. to the ANP, can last up to 27 years. Upon each declaration of commercial Brazil Rio das Contas Quota Purchase Agreement Pursuant to the Rio das Contas Quota Purchase Agreement we entered into field within 180 days. The concessions may be renewed for an additional period equal to their original term if renewal is requested with at least 12 months’ notice, and provided that a default under the concession agreement on May 14, 2013, we agreed to acquire from Panoro all of the quotas issued has not occurred and is then continuing. Even if obligations have been by Rio das Contas for a purchase price of US$140 million (subject to working fulfilled under the concession agreement and the renewal request was capital adjustments at closing and further earn-out payments, if any) upon appropriately filed, renewal of the concession is subject to the discretion of viability, a concessionaire must submit to the ANP a development plan for the satisfaction of certain conditions. With respect to the earn-out payments, the the ANP. Rio das Contas Quota Purchase Agreement provides that during the calendar periods beginning on January 1, 2013 and ending as late as December 31, The main terms and conditions of a concession agreement are set forth 2017, we will make annual earn-out payments to Panoro in an amount equal in Article 43 of the Brazilian Petroleum Law, and include: (1) definition to 45% of “net cash flow,” calculated as EBITDA less the aggregate of of the concession area; (2) validity and terms for exploration and production capital expenditures and corporate income taxes, with respect to the BCAM- activities; (3) conditions for the return of concession areas; (4) guarantees 40 Concession of any amounts in excess of US$25.0 million, up to a maximum to be provided by the concessionaire to ensure compliance with the cumulative earn-out amount of US$20.0 million in a five-year period. Once concession agreement, including required investments during each phase; the maximum earn-out amount is reached or the five-year period has elapsed, (5) penalties in the event of noncompliance with the terms of the concession no further earnout amounts will be payable. agreement; (6) procedures related to the assignment of the agreement; and (7) rules for the return and vacancy of areas, including removal of equipment We financed our Rio das Contas acquisition in part through our Brazilian and facilities and the return of assets. Assignments of participation interests subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas in a concession are subject to the approval of the ANP, and the replacement Credit Facility”) with Itau BBA International plc, which is secured by the of a performance guarantee is treated as an assignment. benefits GeoPark receives under the Purchase and Sale Agreement for Natural Gas with Petrobras. The facility matures five years from March 28, 2014, The main rights of the concessionaires (including us in our concession which was the date of disbursement and bears interest at a variable interest agreements) are: (1) the exclusive right of drilling and production in rate equal to the six-month LIBOR + 3.9%. The facility agreement includes the concession area; (2) the ownership of the hydrocarbons produced; customary events of default, and subject our Brazilian subsidiary to customary (3) the right to sell the hydrocarbons produced; and (4) the right to export covenants, including the requirement that it maintain a ratio of net debt to the hydrocarbons produced. However, a concession agreement set EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. The credit facility also limits the borrower’s ability to pay dividends if the ratio of net forth that, in the event of a risk of a fuel supply shortage in Brazil, the concessionaire must fulfill the needs of the domestic market. In order to debt to EBITDA is greater than 2.5x. We have the option to prepay the facility ensure the domestic supply, the Brazilian Petroleum Law granted the in whole or in part, at any time, subject to a pre-payment fee to be ANP the power to control the export of oil, natural gas and oil products. determined under the contract. Overview of concession agreements The Brazilian oil and gas industry is governed mainly by the Brazilian Among the main obligations of the concessionaire are: (1) the assumption of costs and risks related to the exploration and production of hydrocarbons, including responsibility for environmental damages; (2) compliance with Petroleum Law, which provides for the granting of concessions to operate the requirements relating to acquisition of assets and services from domestic petroleum and gas fields in Brazil, subject to oversight by the ANP. suppliers; (3) compliance with the requirements relating to execution of A concession agreement is divided into two phases: (1) exploration and (2) the minimum exploration program proposed in the winning bid; (4) activities development and production. The exploration phase, which is further for the conservation of reservoirs; (5) periodic reporting to the ANP; divided into two subsequent exploratory periods, the first of which begins on (6) payments for government participation; and (7) responsibility for the the date of execution of the concession agreement, can last from three to costs associated with the deactivation and abandonment of the facilities eight years (subject to earlier termination upon the total return of the in accordance with Brazilian law and best practices in the oil industry. 98 GeoPark 20F A concessionaire is required to pay to the Brazilian government the following: Under the BCAM-40 Concession Agreement, the ANP is entitled to a • a license fee; monthly royalty payment equal to 7.5% of the production of oil and natural • rent for the occupation or retention of areas; gas in the concession area. In addition, in case the special participation • a special participation fee; • royalties; and • taxes. fee 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 investments equivalent to one percent of the field’s gross revenue. Area retention payments are also applicable under the concession agreement. Rental fees for the occupation and maintenance of the concession areas are payable annually. For purposes of calculating these fees, the ANP takes Pursuant to the Rio das Contas Quota Purchase Agreement, we have agreed into consideration factors such as the location and size of the relevant to acquire Rio das Contas’s 10% participation interest in the BCAM-40 concession, the sedimentary basin and the geological characteristics of the Concession. We closed the acquisition on March 31, 2014. relevant concession. A special participation fee is an extraordinary charge that concessionaires Round 11 concession agreements. Additionally, on May 14, 2013, following the 11th oil and gas bidding round pursuant to the Brazilian Petroleum Law, must pay in the event of obtaining high production volumes and/or we were awarded seven new exploratory licenses in Brazil in the REC-T 94 profitability from oil fields, according to criteria established by applicable and REC-T 85 Concessions in the Recôncavo Basin in the State of Bahia and regulations, and is payable on a quarterly basis for each field from the the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions date on which extraordinary production occurs. This participation fee, in the Potiguar Basin in the State of Rio Grande do Norte. We have entered whenever due, varies between 0% and 40% of net revenues depending into seven concession agreements, which we collectively refer to as the on (1) the volume of production and (2) whether the concession is Round 11 Concession Agreements, with the ANP on September 17, 2013, onshore or in shallow water or deep water. Under the Brazilian Petroleum for the right to exploit the oil and natural gas in these seven new license Law and applicable regulations issued by the ANP, the special participation areas. We have paid to the ANP a license fee in the amount of R$10.2 million fee is calculated based on the quarterly net revenues of each field, which (approximately US$4.2 million, at the January 31, 2014 exchange rate of consist of gross revenues calculated using reference prices established by R$2.4263 to US$1.00), consisting of R$7.2 million (approximately US$3.0 the ANP (reflecting international prices and the exchange rate for the million, at the January 31, 2014 exchange rate of R$2.4263 to US$1.00) for period) less: • royalties paid; • investment in exploration; • operational costs; and the REC-T 94 and REC-T 85 Concessions and R$3.0 million (approximately US$1.2 million, at the January 31, 2014 exchange rate of R$2.4263 to US$1.00) for the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions, and provide to the ANP financial guarantees in the amount • depreciation adjustments and applicable taxes. of R$20.4 million (approximately US$8.4 million, at the January 31, 2014 exchange rate of R$2.4263 to US$1.00), consisting of R$12.1 million The Brazilian Petroleum Law also requires that the concessionaire of onshore fields pay to the landowners a special participation fee that varies (approximately US$5.0 million, at the January 31, 2014 exchange rate of R$2.4263 to US$1.00) for the REC-T 94 and REC-T 85 Concessions and R$8.3 between 0.5% to 1.0% of the net operational income originated by the million (approximately US$3.4 million, at the January 31, 2014 exchange field 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 rate of R$2.4263 to US$1.00) for the POT-T 664, POT-T 665, POT-T 619, POT-T 620 and POT-T 663 Concessions, to secure our obligations under the Minimum Exploratory Programs, or PEMs, for the first exploratory period of the concessions. bidding, referred to as Bid Round Zero, under the regime established by Under the Round 11 Concession Agreements, the ANP is entitled to a the Brazilian Petroleum Law. The exploration phase will end in November monthly royalty corresponding to 10% of the production of oil and natural 2029. On September 11, 2009, Petrobras announced the termination of gas in the concession area, in addition to the special participation fee BCAM-40 Concession’s exploration phase and the return of the exploratory described above, the payment for the occupation of the concession area of area of the concession to the ANP, except for the Manatí Field and the approximately R$7,600 (approximately US$3,358, at the March 31, 2014 Camarão Norte Field. exchange rate of R$2.263 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. GeoPark 20F 99 Round 12 concession agreements On November 28, 2013, following the 12th oil and gas bidding round An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph pursuant to the Brazilian Petroleum Law, we were awarded two new 1, of the Brazilian Corporate Law) is the joint liability among consortium exploratory licenses in Brazil, the PN-T-597 Concession on the Parnaiba Basin members as established in the Brazilian Petroleum Law (Article 38, item II). in the State of Maranhão and the SEAL-T-268 Concession in the Sergipe- Alagoas Basin in the State of Alagoas. BCAM-40 Consortium Agreement. On January 14, 2000, the consortium formed by Petrobras, QG Perfurações and Petroserv entered into a Our offer requires a commitment to the ANP of R$9.3 million (approximately consortium agreement, or the BCAM-40 Consortium Agreement, for the US$4.0 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) performance of the BCAM-40 Concession Agreement. Petrobras is the composed of R$1.6 million (approximately US$0.7 million, at the March 31, operator of the BCAM-40 concession, with a 35% participation interest. 2014 exchange rate of R$2.263 to US$1.00) for the first exploratory period on QGEP, Brasoil and Rio das Contas have a 45%, 10% and 10% participation the Concession SEAL-T- 268 and R$7.7 million (approximately US$3.4 million, interest, respectively. The BCAM-40 Consortium Agreement has a specified at the March 31, 2014 exchange rate of R$2.263 to US$1.00) for the first term of 40 years, terminating on January 14, 2040 and, at the time the exploratory period on the PN-T-597. obligations undertaken in the agreement are fully completed, the parties will have the right to terminate it. The BCAM-40 Concession consortium has Part of our bid for the Round 12 concessions was comprised of work also entered into a joint operating agreement, which sets out the rights program guarantees, or commitments to invest certain sums in the blocks as and obligations of the parties in respect of the operations in the concession. part our exploration activities. Our SEAL-T-268 commitment is composed of R$0.14 million (approximately US$0.07 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) bonus payable to the ANP and R$1.5 Petrobras Natural Gas Purchase Agreement QGEP, Rio das Contas, Brasoil and Petrobras are party to a natural gas million (approximately US$0.7 million, at the March 31, 2014 exchange rate purchase agreement providing for the sale of natural gas by QGEP, Rio das of R$2.263 to US$1.00) as part of the work program guarantee payable over Contas and Brasoil to Petrobras, in an amount of 812 bcf over the term of the course of the three years. Work program is equivalent to 40 km of 2D agreement. The Petrobras Natural Gas Purchase Agreement is valid until the seismic, with no well drilling committed during the first exploratory period. earlier of Petrobras’s receipt of this total contractual quantity or June 30, 2030. The agreement may not be fully or partially assigned except upon Our PN-T-597 commitment is composed of R$0.9 million (approximately US$0.4 execution of an assignment agreement with the written consent of the other million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) bonus parties, which consent may not be unreasonably withheld provided that payable to the ANP in the first year of exploration and R$6.7 million certain prerequisites have been met. (approximately US$3.0 million, at the March 31, 2014 exchange rate of R$2.263 to US$1.00) as a work program guarantee. See “Item 3. Key information—D. Risk The agreement provides for the provision of “daily contractual quantities” factors—Risks relating to our business—The PN-T-597 concession is subject to to Petrobras, in the following amounts: from the first year through the an injunction and may not close.” for more information. end of the fourth year under the contract, 211.9 mmcfpd; from the beginning of the fifth year through the end of the ninth year, 141.3 mmcfpd; and Overview of consortium agreements A consortium agreement is a standard document describing consortium from the beginning of the tenth year through the end of the contract, 141.3 mmcfpd or such smaller quantity as stipulated by the parties, to take members’ respective percentages of participation and appointment of into account the Manatí Field’s depletion. Pursuant to the agreement, the operator. It generally provides for joint execution of oil and natural gas the base price is denominated in reais and is adjusted annually for inflation exploration, development and production activities in each of the pursuant to the general index of market prices (IGPM). Additionally, the concession areas. These agreements set forth the allocation of expenses gas price applicable on a given day is subject to reduction as a result of the for each of the parties with respect to their respective participation interests gas quantity acquired by Petrobras above the volume of the annual TOP in the concession. The agreements are supplemented by joint operating commitment (85% of the daily contracted quantity) in effect on such day. agreements, which are private instruments that typically regulate the aggregation of funds, the sharing of costs, mitigation of operational risks, The Petrobras Natural Gas Purchase Agreement provides that if the Manatí preemptive rights and the operator’s activities. Field’s daily production capacity is less than the amount of the applicable daily contractual quantity, gas sales shall be made exclusively to Petrobras, with any sales to third parties subject to a penalty. If the field’s production is 100 GeoPark 20F above the applicable daily contractual quantity, the agreement provides for 35 years. The term of each of these concessions is 25 years, with an that Petrobras must first be offered to purchase the excess amount of gas. optional extension of up to 10 years. There is no minimum work or investment commitment under any of the concessions other than the general Petrobras Natural Gas Condensate Purchase Agreement On January 1, 2014, Rio das Contas and Petrobras entered into an agreement, requirement to make needed investments to develop the entire acreage of the concession, though the Argentine Secretary of Energy takes into the Petrobras Natural Gas Condensate Purchase Agreement, valid until account all work and investment undertaken when determining whether December 31, 2015 for the sale to Petrobras of Rio das Contas’s share of the to grant an extension of the concession term. Work and investment total volume of natural gas condensate to be produced in the Manatí Field. programs for the concessions are required to be presented annually to the The agreement can be renewed and takes into consideration market factors incumbent Provincial State enforcement authority, the Argentine Secretary that affect the production and sale of gas. of Energy and the Strategic Planning and Coordination Committee for the National Hydrocarbon Investment Plan. Pursuant to the agreement, for each liquid barrel of condensed natural gas sold by Rio das Contas, Petrobras will pay the monthly arithmetic average Under the terms of our concession agreements, we are entitled to 100% of of the averages of the daily prices for the “BRENT DTD” barrel, as published production, with no governmental participation. We are also required, under by Platt’s Crude Oil Marketwire, subject to a discount of $2.87 per barrel. Argentine law, to pay royalties to certain Argentine provinces, at a rate of 12% on both oil and gas sales. In addition to this 12% royalty, we are also Any assignment of a party’s interest under the agreement requires the other required to pay additional royalties ranging from 2.5% to 8%, pursuant to party’s prior written consent. Argentina Overview of exploitation concessions As the concession holder of three concessions in Argentina—the Del private royalty agreements we have entered into. We also pay annual surface rental fees established under hydrocarbons law 17.319 and Resolution 588/98 of the Argentine Secretary of Energy and Decree 1454/2007, and certain landowner fees. Mosquito Concession, the Cerro Doña Juana Concession and the Loma Our Argentine concession agreements have no change of control provisions, Cortaderal Concession— we are subject to numerous restrictions and fees though any assignment of these concessions is subject to the prior related to hydrocarbon production and foreign markets. For example, authorization by the executive branch of the incumbent Provincial State. the domestic oil and gas market in Argentina has supply privileges favoring For the four years prior to the expiration of each of these concessions, the domestic market, to the detriment of the export market, including the concession holder must provide technical and commercial justifications hydrocarbon export restrictions, domestic price controls, export duties and for leaving any inactive and non-producing wells unplugged. Each of these domestic market supply obligations. We are also subject to certain foreign concessions can be terminated for default in payment obligations and/or currency retention restrictions. We must comply with central bank breach of material statutory or regulatory obligations. We may also voluntarily registration requirements, maintain a minimum one-year residency in relinquish acreage to the Argentine authorities. For example, in November Argentina and comply with central bank registration requirements, including the requirement that 30% of all funds remitted to Argentina remain 2012, we voluntarily relinquished approximately 102,500 non-producing gross acres in the Del Mosquito Block to the Argentine authorities, which deposited in a domestic financial institution for one year without yielding relinquishment is currently subject to approval by the authorities of the interest unless such funds are proven invested in exploration and production province of Santa Cruz and the completion of certain environmental audits. or meet other limited requirements, as established under Presidential Decree In addition, in April 2014, we informed the Secretary of Infrastructure and 616/2005. We are also subject to certain export duties under each of the Energy of the Province of Mendoza of our decision to relinquish 100% concessions (in particular, to a 20% duty on gas exports, as established under of the Cerro Doña Juana and Loma Cortaderal Concessions to the Mendoza Presidential Decree 645/2004) and an up-to-45% duty on oil exports, Province. The area covered by the Cerro Doña Juana and Loma Cortaderal depending on oil prices, as established under Resolution 394/2007 of the blocks is 47.9 acres and neither the Cerro Doña Juana nor the Loma Cortaderal Argentine Secretary of Energy. are currently in production or have any associated reserves. Relinquishment is subject to approval by the authorities of the province of Mendoza. In general, our Argentina concession agreements for the Del Mosquito, Cerro Doña Juana and Loma Cortaderal Blocks grant us the exclusive right Our Argentine concessions are governed by the laws of Argentina and the to produce, explore and develop hydrocarbons in these blocks, as well resolution of any disputes must be sought in the Federal Courts, although as the right to receive a transportation concession to build unused pipelines provincial courts may have jurisdiction over certain matters. or other transportation facilities beyond the boundaries of the concessions GeoPark 20F 101 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 develop upstream oil and gas projects in Latin America. In 2011, LGI acquired future investments, costs and obligations. See “Item 3. Key Information—D. a 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark Risk factors—Risks relating to our business—LGI, our strategic partner in TdF, for a total consideration of US$148.0 million, plus additional equity Chile and Colombia, may sell its interest in our Chilean and Colombian funding of US$18.0 million over the following three years. On May 20, 2011, operations to a third party or may not consent to our taking certain actions.” 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 Chile Shareholders’ Agreement) and a subscription agreement (as amended LGI Colombia Agreements In December 2012, we and LGI agreed that we would extend our strategic on July 4, 2011 and October 4, 2011, in connection with LGI’s investment partnership to build a portfolio of upstream oil and gas assets throughout in GeoPark TdF, the GeoPark TdF Subscription Agreement, and, together with Latin America through 2015. On December 18, 2012, LGI agreed to acquire a the GeoPark Chile Shareholders’ Agreement, the LGI Chile Shareholders’ 20% equity interest in GeoPark Colombia for a total consideration of Agreements), setting forth our and LGI’s respective rights and obligations in US$20.1 million composed of a US$14.9 million capital contribution, a US$4.9 connection with LGI’s investment in our Chilean oil and gas business. million loan to GeoPark Colombia and miscellaneous reimbursements. Concurrently, we and LGI entered into a shareholders’ agreement, the LGI The respective boards of each of GeoPark Chile and GeoPark TdF supervise Colombia Shareholders’ Agreement, setting forth our and LGI’s respective their day-to-day operations. Each of these boards has four directors. As long obligations in connection with LGI’s investment in our Colombian oil as LGI holds at least 5% of the voting shares of GeoPark Chile, LGI has the and gas business, and LGI and Winchester (now GeoPark S.A.S.) entered into right to elect one director and such director’s alternate, and the remaining a loan agreement, whereby, upon the closing of LGI’s subscription of shares directors, and alternates, are elected by us. As long as LGI holds at least in GeoPark Colombia, LGI granted a credit line (of which US$4.9 million 5% of the voting shares of GeoPark TdF, LGI has the right to elect one director was drawn at closing) to Winchester (now GeoPark S.A.S.) of up to US$12.0 and such director’s alternate, and the remaining directors, and alternates, million, to be used for the acquisition, development and operation of oil and are elected by GeoPark Chile. gas assets in Colombia. Further, on January 8, 2014, following an internal corporate reorganization of our Colombian operations, GeoPark Colombia The LGI Chile Shareholders’ Agreements require the consent of LGI or Coöperatie U.A. and GeoPark Latin America entered into a new members’ the LGI appointed director in order for GeoPark Chile and GeoPark TdF, as agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out the case may be, to take certain actions, including, among others: substantially similar rights and obligations to the LGI Colombia Shareholders’ • making any decision to terminate or permanently or indefinitely suspend Agreement in respect of our oil and gas business in Colombia. We refer to operations in or surrender our blocks in Chile (other than as required under the LGI Colombia Shareholders’ Agreement and the LGI Colombia Members’ the terms of the relevant CEOP for such blocks); Agreement collectively as the LGI Colombia Agreements. • selling our blocks in Chile to our affiliates; • any change to the dividend, voting or other rights that would give GeoPark Colombia’s board supervises its day-to-day operations. GeoPark preference to or discriminate against the shareholders of GeoPark Chile Colombia has four directors. As long as LGI holds at least 14% of the voting and GeoPark TdF; shares of GeoPark Colombia, LGI has the right to elect one director and • entering into certain related party transactions; and such director’s alternate, and the remaining directors and alternates are • creating a security interest over our blocks in Chile (other than in elected by us. connection with a financing that benefits our Chilean subsidiaries). The LGI Chile Shareholders’ Agreements provide that if LGI or either Agencia existing debt of GeoPark Colombia and to provide additional funding to or GeoPark Chile decides to sell its shares in GeoPark Chile or GeoPark cover LGI’s share of required future investments in Colombia. In addition, we TdF, as the case may be, the transferring shareholder must make an offer to can earn back up to 12% additional equity interests in GeoPark Colombia sell those shares to the other shareholder before selling those shares to a depending on the success of our Colombian operations. Under the LGI Colombia Agreements, LGI agreed to assume its share of the third party. In addition, any sale to a third party is subject to tag-along and drag-along rights, and the non-transferring shareholder has the right to The LGI Colombia Agreements require the consent of LGI or the LGI- object to a sale to the third-party if it considers such thirdparty to be not appointed director for GeoPark Colombia to take certain actions, including, of a good reputation or one of our direct competitors. Under the LGI Chile among others: 102 GeoPark 20F • making any decision to terminate or permanently or indefinitely suspend the Republic of Colombia grants such rights through E&P Contracts or operations in or surrender our blocks in Colombia (other than as required contracts of association. In Argentina, the Argentine Republic grants such under the terms of the relevant concessions for such blocks); rights through exploitation concessions. In Brazil, the Federative Republic of • creating of a security interest over our blocks in Colombia; Brazil grants such rights pursuant to concession agreements. See “Item 3. • approving of GeoPark Colombia’s annual budget and work programs and Key Information—D. Risk factors—Risks relating to the countries in which the mechanisms for funding any such budget or program; we operate—Oil and natural gas companies in Chile, Colombia, Brazil • entering into of any borrowings other than those provided in an approved and Argentina do not own any of the oil and natural gas reserves in such budget or incurred in the ordinary course of business to finance working countries.” Other than as specified in this annual report, we believe that we capital needs; have satisfactory rights to exploit or benefit economically from the oil and • granting any guarantee or indemnity to secure liabilities of parties other gas reserves in the blocks in which we have an interest in accordance than those of our Colombian subsidiaries; with standards generally accepted in the international oil and gas industry. • changing the dividend, voting or other rights that would give preference to Our CEOPs, E&P Contracts, contracts of association, exploitation concessions or discriminate against the shareholders of GeoPark Colombia; and concession agreements are subject to customary royalty and other • entering into certain related party transactions; and interests, liens under operating agreements and other burdens, restrictions • disposing of any material assets other than those provided for in an and encumbrances customary in the oil and gas industry that we believe approved budget and work program. do not materially interfere with the use of or affect the carrying value of our interests. See “Item 3. Key Information—D. Risk factors—Risks relating We have also agreed to ensure that the board of directors and rules and to our business—We are not, and may not be in the future, the sole owner management of our other subsidiaries engaged in our Colombian oil and gas or operator of all of our licensed areas and do not, and may not in the future, business are subject to the same principles and restrictions outlined above. hold all of the working interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development The LGI Colombia Agreements provide that if either we or LGI decide to sell efforts, associated costs, or the rate of production of any non-operated and, our respective shares in GeoPark Colombia, the transferring shareholder must to an extent, any non-wholly-owned, assets.” make an offer to 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 drag-along rights, and the non-transferring shareholder has Our customers In Chile, our primary customers are ENAP and Methanex. As of December the right to object to a sale to the third-party if it considers such third-party 31, 2013, ENAP purchased all of our oil and condensate production to be not of a good reputation or one of our direct competitors. and Methanex purchased 99% of our natural gas production in Chile, and represented 39.8% and 6.7%, respectively, of our total revenues for the Under the LGI Colombia Agreements, we and LGI have agreed to vote our year ended December 31, 2013. Our contract with ENAP is automatically common shares or otherwise cause GeoPark Colombia to declare dividends renewed for six-month terms, with oil pricing based on international only after allowing for retentions for approved work programs and budgets and capital adequacy requirements of GeoPark Colombia, working capital market prices. Our contract with Methanex is a long-term contract subject to take-or-pay and deliver-or-pay provisions, with the price of natural requirements, banking covenants associated with any loan entered into gas based on the international market prices for methanol. In Colombia, by GeoPark Colombia or our other Colombian subsidiaries and operational our primary customers are Gunvor, Hocol, Perenco and Trenaco, who requirements. See “Item 3. Key Information— D. Risk factors—Risks relating purchase our production through short-term contracts, and who represented to our business—LGI, our strategic partner in Chile and Colombia, may 27.8%, 11.1%, 5.2% and 3.9%, respectively, of our total revenues for the sell its interest in our Chilean and Colombian operations to a third party or year ended December 31, 2013. In Argentina, our primary customer is may not consent to our taking certain actions.” Oil Combustibles, representing 0.5% of our total revenues for the year ended Title to properties In each of the countries in which we operate, the state is the exclusive owner December 31, 2013. Having closed our Brazil acquisitions on March 31, 2014, we expect our primary customer in Brazil to be Petrobras. of all hydrocarbon resources located in such country and has full authority to determine the rights, royalties or compensation to be paid by private Seasonality Although there is some historical seasonality to the prices that we receive investors for the exploration or production of any hydrocarbon reserves. for our production, the impact of such seasonality has not been material. In Chile, the Republic of Chile grants such rights through a CEOP. In Colombia, Additionally, seasonality does not play a significant role in our ability to GeoPark 20F 103 conduct our operations, including drilling and completion activities. Although Health, safety and environmental matters in winter months, it is more difficult or even impossible to conduct certain of our operations, such as seismic work, we take such seasonality into account in planning for and conducting our operations, such that the impact on our General We and our operations are subject to various stringent and complex overall business is not material. Our competition The oil and gas industry is competitive, and we may encounter strong international, federal, state and local environmental, health and safety laws and regulations in the countries in which we operate governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use and transportation of regulated competition from other independent operators and from major oil companies materials; and human health and safety. These laws and regulations may, in acquiring and developing licenses. In Chile, we partner with and sell among other things: to, and may from time to time compete with, ENAP and, to a lesser extent, • require the acquisition of various permits or other authorizations or the some companies with operations in Argentina mentioned below. In preparation of environmental assessments, studies or plans (such as well Colombia, we partner with and sell to, and may from time to time compete closure plans) before seismic or drilling activity commences; with, Ecopetrol, as well as with privately-owned companies such as Pacific • enjoin some or all of the operations of facilities deemed not in compliance Rubiales, Gran Tierra, Petrominerales, Parex and Canacol, among others. with permits; In Brazil, we partner with and sell to, and may from time to time compete • restrict the types, quantities and concentration of various substances that with, Petrobras, privately-owned companies such as HRT, QGEP, Brasoil and can be released into the environment in connection with oil and natural gas some of the Colombian companies mentioned above, which have entered drilling, production and transportation activities; into Brazil, among others. In Argentina, we compete for resources with YPF, • require establishing and maintaining bonds, reserves or other commitments as well as with privately-owned companies such as Pan American Energy, to plug and abandon wells; Pluspetrol, Tecpetrol, Chevron, Wintershall, Total, Sinopec and others. • limit or prohibit seismic and drilling activities in certain locations lying within or near protected or otherwise sensitive areas; and Many of these competitors have financial and technical resources and • require remedial measures to mitigate or remediate pollution from our personnel substantially larger than ours. As a result, our competitors may operations, which, if not undertaken, could subject us to substantial penalties. be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or These laws and regulations may also restrict the rate of oil and natural gas personnel resources will permit. Furthermore, these companies may also be production below the rate that would otherwise be possible. Compliance better able to withstand the financial pressures of unsuccessful wells, with these laws can be costly. The regulatory burden on the oil and gas sustained periods of volatility in financial and commodities markets and industry increases the cost of doing business in the industry and generally adverse global and industry-wide economic conditions, and may consequently affects profitability. be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our Moreover, public interest in the protection of the environment continues to increase. Drilling in some areas has been opposed by certain community business—Competition in the oil and natural gas industry is intense, which and environmental groups and, in other areas, has been restricted. Our makes it difficult for us to acquire properties and prospects, market oil operations could be adversely affected to the extent laws are enacted and natural gas and secure trained personnel.” or other governmental action is taken that prohibits or restricts seismic or drilling activities or imposes environmental requirements that result in We are also affected by competition for drilling rigs and the availability of increased costs to the oil and gas industry in general, such as more stringent related equipment. Higher commodity prices generally increase the demand or costly waste handling, disposal or cleanup requirements. for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past several years, oil and natural gas companies have Climate change Our operations and the combustion of oil and natural gas-based products experienced higher drilling and operating costs. Shortages of, or increasing results in the emission of greenhouse gases, which may contribute to global costs for, experienced drilling crews and equipment and services could climate change. Climate change regulation has gained momentum in recent restrict our ability to drill wells and conduct our operations. years internationally and at the federal, regional, state and local levels. On the international level, various nations have committed to reducing their greenhouse gas emissions pursuant to the Kyoto Protocol. The Kyoto 104 GeoPark 20F Protocol was set to expire in 2012. In late 2011, an international climate life, wildlife protected areas, water quality standards, air emissions and change conference in Durban, South Africa resulted in, among other things, soil pollution. In addition, violations of these environmental regulations an agreement to negotiate a new climate change regime by 2015 that may lead to fines, the closure of facilities and the revocation of environmental would aim to cover all major greenhouse gas emitters worldwide, including approvals. The General Environmental Law and its regulations entitle the the U.S., and take effect by 2020. In November and December 2012, at an Chilean government, through the Superintendency of the Environment, international meeting held in Doha, Qatar, the Kyoto Protocol was extended to: (1) bring administrative and judicial proceedings against companies that by amendment until 2020. In addition, the Durban agreement to develop the violate environmental laws; (2) close non-complying facilities; (3) revoke protocol’s successor by 2015 and implement it by 2020 was reinforced. required operating licenses; and (iv) impose sanctions and fines when companies act negligently, recklessly or deliberately in connection with Other regulation of the oil and gas industry environmental matters. Chile Companies in the oil and gas sector, like all Chilean companies, must comply with the general principles concerning employee health and safety laws that The sanction procedures and environmental liability claims derived from environmental damage will be handled by the Chilean environmental court. are contained in the Chilean Labor Code and other labor statutes. The Chilean For additional information on environmental, health and safety regulations Ministry of Labor is responsible for the enforcement of those standards, with applicable to the Chilean oil and gas sector, see “—Industry and regulatory the authority to impose fines. In addition, the Health Department of the framework—Chile—Regulatory entities.” 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 Regarding environmental matters, the Chilean Constitution grants all Colombia is dispersed throughout a number of different laws and citizens the right to live in a pollution-free environment. It further provides regulations. Environmental regulation is primarily governed by Law 99 of that other constitutional rights may be limited in order to protect the 1993, which established the Ministry of Environment and provided for environment. Chile has numerous laws, regulations, decrees and municipal the issuance of a number of associated laws and regulations. The Ministry ordinances relating to environmental protection, pursuant to which specific of Environment through the ANLA monitors compliance with environmental approvals, consents and permits may be required in order to perform obligations. Furthermore, licenses for exploration and exploitation of activities that may affect the environment. hydrocarbons are granted by the ANLA and this is the entity in charge of monitoring the permits. Regional corporations who are responsible for The General Environmental Law (Law No. 19,300), enacted in March 1994 monitoring environmental compliance within their regions have and modified in 2010 by Law No. 20,417, establishes a framework for additional obligations. environmental regulation in Chile, which has become increasingly stringent in recent years. Recent amendments include, among others, the creation of a new institutional framework composed of: (1) the Ministry of Law 99 introduced the requirement of environmental permits for activities, including oil and gas exploration and production, which can cause serious Environment (Ministerio del Medio Ambiente); (2) the Council of Ministers deterioration of renewable natural resources or damage to the environment, for Sustainability (Consejo de Ministros para la Sustentabilidad); (3) the or that introduce substantial changes to the landscape. Decree 2820 of Environmental Assessment Service (Servicio de Evaluación Ambiental); and 2010 requires an environmental license for all hydrocarbon projects, including (4) the Superintendency of the Environment (Superintendencia del Medio for each of the following activities: conducting seismic exploration activities Ambiente), all of which are in charge of regulating, assessing and enforcing that require the construction of roads for vehicular traffic, exploratory drilling activities that could have an environmental impact. Recent modifications projects, exploitation of hydrocarbons and development of related facilities introduced to existing regulations also gives right for public participation (including internal pipelines and storage, roads and related infrastructure), for interested people and non-governmental organizations in the assessment transportation and handling of liquid and gaseous hydrocarbons, developing of projects, which could result in additional delays for the final approval of liquid hydrocarbon delivery terminals or transfer stations, and construction new projects. and operation of refineries. Other hydrocarbon activities may require environmental permits as well. Compliance with environmental regulations The new institutions and regulatory framework are likely to result in is handled under a strict sanctioning regime, established by Law 1333 of additional restrictions or costs on us relating to environmental litigation and 2009, whereby liability is presumed and fines are significant. protection of the environment, particularly those related to plant and animal GeoPark 20F 105 Legislation governing Health and Safety is varied, but mainly focuses on CONAMA Resolution No. 237 sets forth the general rules that must the Law 1562 of 2012, issued by the Colombian Congress through the System be complied with regarding environmental licensing. It prescribes that the of Occupational Hazards. competent environmental authority, with the entrepreneur’s participation, shall define the plans, projects and environmental assessments necessary Law 1010 of 2006 established actions to prevent, correct and punish to start the environmental licensing proceeding. In addition, IBAMA labor bullying; Resolution 2646 of 2008 of the Ministry of Health and Social Normative Ordinance No. 184, from July 17, 2008, defines the general rules Protection establishes responsibilities for the identification, assessment, of environmental licensing on the federal level. However, for oil and prevention, intervention and ongoing monitoring of exposure to psychosocial gas activities, these general rules do not apply and have been adjusted and risk factors at work and for determining the origin of defined diseases caused regulated by specific regulation, as mentioned below. by occupational stress; among others. For additional information on environmental, health and safety regulations seismic activities. Ordinance No. 422, from October 26, 2011, issued by the applicable to the Colombian oil and gas sector, see “—Industry and Brazilian Ministry for the Environment, sets forth rules for the environmental regulatory framework—Colombia—Regulatory entities.” licensing of: (1) seismic activities (i.e., clarifying and creating some new CONAMA Resolution No. 350/2004 governs environmental licensing for steps between those mentioned above); (2) drilling; and (3) oil and gas Brazil In accordance with Brazilian environmental legislation, activities or ventures production and evacuation, as well as Extended Well Tests, or EWTs. For the environmental licensing of oil and gas production and evacuation, as well that use natural resources or that are deemed to be actually or potentially as EWTs, the proceeding is more complex. The steps differ depending on the polluting are subject to environmental licensing requirements, under which status of the enterprise and the environmental license sought: (1) planning the relevant environmental body analyzes location, facilities, expansion and for the installation of the enterprise, which needs a Preliminary License operation of projects, as well as establishes conditions for project development. (Licença Prévia), or LP; (2) implementation and installation of the project licensed with the LP, which needs an Installation License (Licença de Environmental licensing of E&P activities in the offshore basin (territorial sea, Instalação) or LI; and (3) operation of the enterprise installed according with the continental platform and exclusive economic zones) is granted on a the LI, which needs an Operation License (Licença de Operação). federal level. The environmental licensing in Brazil may be subject to federal, state or municipal (local) licensing as a general rule, and in many industries The environmental licensing of oil and natural gas exploration, development it is usual to have projects in which more than one of those entities claim and production activities is subject to, among several other requirements, jurisdiction. That may be the case for onshore E&P activities (and it is in the the preparation of environmental assessments, the complexity and rules ports sector, for instance), but such controversy does not apply to offshore of which vary according to the activities sought, the depth and distance from E&P environmental licensing. the coast and the environmental sensitivity of the area in which the development of activities is sought. Among such studies, the Environmental The IBAMA, by means of its General Supervision for Oil and Gas Licensing (Coordenação Geral de Licenciamento de Petróleo e Gás), is the entity in Impact Assessment (Estudo Prévio de Impacto Ambiental) and the respective Environmental Impact Report (Relatório de Impacto de Ambiental) may be charge of the environmental licensing for E&P projects. deemed the most complex and time-demanding environmental assessment, E&P activities are divided in two subgroups, according to the Brazilian an Environmental Drilling Study (Estudio Ambiental de Perfuração) may also Ministry for the Environment: (i) seismic activities; and (ii) drilling and be required for purposes of respective environmental licensing. This is a very production of hydrocarbons. In addition to the Complementary Law, the comprehensive, tailor-made analysis of the environmental impacts, to be though an Environmental Seismic Study (Estudio Ambiental de Sísmica) or main rules governing the environmental licensing of such activities produced by the enterprise. are: (1) Resolution No. 237, from December 19, 1997, issued by the Brazilian National Committee for the Environment (Conselho Nacional do Meio- As a compensatory measure, we are also obligated to allocate funds for the Ambiente), or CONAMA; (2) Resolution No. 350, from July 6, 2004, also issued implementation and maintenance of conservation areas, based on Federal by CONAMA; and (3) Ordinance No. 422, from October 26, 2011, issued by Law No. 9,985/2000, which are evaluated by the competent environmental the Brazilian Ministry for the Environment. agency on the basis of Federal Decree Nos. 4,340/2002 and 6,848/2009 and which must not exceed the value of 0.5% of the total cost involved for the construction of the facility. 106 GeoPark 20F Failure to maintain a valid environmental license is classified as an In the administrative sphere, Federal Decree No. 6,514/2008 provides that administrative infraction and environmental crime. Any delays or denials environmental authorities may also impose administrative sanctions for by the environmental licensing authority in issuing or renewing licenses, those who do not comply with environmental laws and regulations, as well as the inability to meet the requirements established by the including, among others: simple fines from R$50 to R$50 million, depending environmental authorities during the environmental licensing process, may on the infraction, e.g., absence of environmental licenses or failure to harm or even prevent the construction and regular development of the comply with its terms may subject the entrepreneur to a fine ranging from activity. Some environmental licenses related to operation of the Manatí R$500 to R$10 million, daily fines, partial or total suspension of activities, Field production system and natural gas pipeline are expired. However, demolition of the enterprise and rights restriction sanctions, such as forfeiture the operator submitted, timely, the request for renewal of those licenses and or restriction of tax incentives or benefits, closing of the establishments as such this operation is not in default as long as the regulator does not or ventures and forfeiture or suspension of participation in credit lines state its final position on the renewal. with official credit establishments. 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 applicable to the Brazilian oil and gas sector, see “—Industry and regulatory fact that the relevant entity’s operations are covered by environmental framework—Brazil—Regulatory entities.” licenses 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 Argentina Historically, environmental legislation and enforcement powers in respect environmental damages and intensity thereof. The victim of such damages of oil and gas operations have been vested with the federal government. or whomever the law so authorizes, as indicated below, is not compelled However, after the 1994 constitutional reform and after the enactment of the to sue all polluting agents within the same proceeding. Because liability is of YPF Privatization Law in 1992, provincial states have passed and enforced a joint nature, the aggrieved party may choose one out of all polluting concurrent new environmental legislation. The federal government is agents (for example, the agent with the best economic standing) to redress empowered to establish minimum environmental protection standards and all damages. A polluting agent so sued will have a right of recourse against provincial governments are empowered to complement them, though the other polluting agents. provincial environmental legislation is not always fully consistent with federal environmental legislation. Furthermore, under Brazilian law, due to environmental damages and noncompliance with environmental laws and regulations, individuals or The oil and natural gas industry in Argentina is subject to environmental entities are also subject to criminal and administrative sanctions. regulations pursuant to concurrent provincial state and federal legislation. Such legislation provides for restrictions and prohibitions on the release In the criminal sphere, the Environmental Crimes Act (Federal Law No. or emission of various substances produced in association with certain oil 9,605/98) applies to every individual or legal entity that carries out any and gas industry operations. In addition, such legislation requires that wells, activity deemed damaging to the environment. Because criminal facilities and sites be abandoned, reclaimed and/or remediated according liability is of a subjective nature, the Environmental Crimes Act attributed to specific standards and/or to the satisfaction of governmental authorities liability to representatives of legal entities. As a result, upon occurrence and/or surface owners. Compliance with such legislation can require of an environmental violation, a legal entity’s officer, administrator, director, significant expenditures and a breach of such requirements may result in manager, agent or attorney-in-fact may also be subject to criminal penalties, suspension or revocation of necessary licenses and authorizations, civil which comprise fines and imprisonment. With respect to judicial actions, and criminal liability for pollution damage and the imposition of material a civil or administrative settlement does not prevent prosecution in a criminal fines and penalties. sphere should an environmental crime have occurred. GeoPark 20F 107 Environmental regulations in Argentina also require that wells be plugged in and that facility sites be abandoned and returned to Argentina in a Certain Bermuda law considerations As a Bermuda exempted company, we and our Bermuda subsidiaries are state deemed satisfactory to the applicable regulatory authorities. Four subject to regulation in Bermuda. We have been designated by the Bermuda years prior to the expiration of any hydrocarbon concession granted by Monetary Authority as a non-resident for Bermuda exchange control the Argentine government, an operator is required to present any technical purposes. This designation allows us to engage in transactions in currencies or commercial reasons for seeking to leave an inactive and non-producing other than the Bermuda dollar, and there are no restrictions on our ability well unplugged to the applicable regulatory authorities. In addition, to transfer funds (other than funds denominated in Bermuda dollars) in and the province of Santa Cruz, in which the Del Mosquito block is located, out of Bermuda. has created a Registry of Environmental Liabilities and requires operators to submit a five-year remediation program for all environmental liabilities Under Bermuda law, “exempted” companies are companies formed for the that have been registered. 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 on licensed in Bermuda. 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 either because such insurance is not available or because premium costs and workers’ rights issues and applicable World Bank standards. are considered prohibitive. Our policy is to strive to meet or exceed environmental regulations in the Currently, our insurance program includes, among other things, construction, countries in which we operate. We believe that oil and gas can be produced in fire, vehicle, technical, umbrella liability, director’s and officer’s liability an environmentally-responsible manner with proper care, understanding and and employer’s liability coverage. Our insurance includes various limits and management. We have within our S.P.E.E.D. program a team that is exclusively deductibles or retentions, which must be met prior to or in conjunction focused on securing the environmental authorizations and permits for the with recovery. A loss not fully covered by insurance could have a materially projects we undertake. This team is also responsible for the achievement of the environmental standards set by our board of directors and for training and adverse effect on our business, financial condition and results of operations. See “Item 3. Key Information—D. Risk factors—Risks relating to our supporting our personnel. In these activities, we are supported by experienced business—Oil and gas operations contain a high degree of risk and we may oil and gas environmental consulting firms. Our senior executives have also not be fully insured against all risks we face in our business.” received training in proper environmental management. Our health and safety policy We believe that the implementation of additional safety tools in our operations in 2012 have significantly contributed to control and minimizing risks in our operation. Actions taken by us included training, permits to work, internal audits, drills, tailgate safety meetings, job safety analysis and risk evaluations. As of December 31, 2013, on a rolling 12-month basis, our Lost Time Incident Rate was 0.62, and our Total Recordable Incident Rate was 0.95 (based on a rate of 200,000 labor hours) compared to 0.83 and 0.99, respectively, in December 2012. We had no fatalities due to workforce incidents related to our operations in 2012 and 2013. 108 GeoPark 20F Industry and regulatory framework Global oil and gas industry During 2012, the growth rate of energy consumption globally dropped According to the BP Statistical Review, global proved natural gas reserves at the end of 2012 remained stable at 187.3 trillion cubic meters, enough to meet 55.7 years of 2012’s global production. South and Central America currently hold 4.1% of global proved natural gas reserves. During 2012, global following (1) the global economic slowdown and (2) a more efficient use of natural gas production averaged 3363.9 billion cubic meters, an increase of energy as a response to the high price environment of recent years. 1.9% over 2011. Global oil consumption in 2012 grew by 895,000 bopd, or 0.9%, compared to 2011, to reach 89,774,000 bopd. On the other hand, global oil production in Distribution of proved natural gas reserves in 1992, 2002 and 2012 Percentage 2012 increased by 1.9 mmbopd, or 2.2%, to reach 86.2 mmbopd. Global natural gas consumption in 2012 grew by 7.1 bcfpd, or 2.3%, to reach 319.8 bcfpd, while global natural gas production in 2012 grew by 6.2 bcfpd, or 1.9%, to reach 324.6 bcfpd, with the United States recording the largest volumetric increases in natural gas consumption and production. In 2012, the United States posted the largest oil and natural gas production gains worldwide, and saw the largest increase in oil production in its history. Elsewhere, for a second year, disruptions to oil supply in Africa and parts of the Middle East were offset by growth among OPEC producers according to the BP Statistical Review of World Energy June 2013, or the BP Statistical Review. Middle East Europe & Eurasia S. & Cent. America Africa North America Asia Pacific 3.6 5.9 63.7 8.3 17.3 7.5 11.7 7.6 7.8 2.5 48.4 3.1 7.7 56.1 8.4 13.2 7.6 19.7 1992 - Total 1039.3 thousand million barrels 2002 - Total 1321.5 thousand million barrels 2012 - Total 1668.5 thousand million barrels World proved oil reserves at the end of 2012 reached 1,668.9 billion barrels (up 0.9% in relation to 2011), enough to meet 52.9 years of 2012’s global Source: BP Statistical Review production, according to the BP Statistical Review. In 2012, South and Central America contributed 19.7% of global proved oil reserves, with Venezuelan The industry’s outlook is gradually shifting, driven mainly by supply patterns. reserves as reported by BP Statistical Review being the main source of According to BP’s Energy Outlook 2030, global energy demand is production (totaling 297.6 bbopd). Global oil production averaged 86.2 expected to grow by 36% between 2011 and 2030 as a result of increasing mmbopd (an increase of 2.2% over 2011). Throughout the last twenty years, consumption by emerging economies (with China and India becoming the overall contribution of South and Central America to global proved oil increasingly more import-dependent). On the supply side, unconventional reserves has increased dramatically as a result of the emergence of markets oil and gas resources are expected to play a major role in balancing like Brazil and Ecuador coupled with the dramatic increase of reserves in global demand, with the United States leading this process. BP projects that Venezuela (by 370% during the same period). between 2011 and 2030, the United States will become self-sufficient in Distribution of proved oil reserves in 1992, 2002 and 2012 Percentage Middle East Europe & Eurasia S. & Cent. America Africa North America Asia Pacific 3.6 5.9 63.7 8.3 17.3 7.5 11.7 7.6 7.8 2.5 48.4 3.1 7.7 56.1 8.4 13.2 7.6 19.7 1992 - Total 1039.3 thousand million barrels 2002 - Total 1321.5 thousand million barrels 2012 - Total 1668.5 thousand million barrels Source: BP Statistical Review energy, while key emerging markets, namely China and India, will become increasingly importdependent. Chile Chile is recognized as the most developed and stable economy in South America. The country’s economy has grown consistently during the last two decades, a trend which is expected to continue in the near future. With over 50 free trade agreements, Chile is an open-market economy, and in 2010, became the first South American country to join the Organisation for Economic Co-operation and Development, or the OECD. The country’s fiscal policy follows a countercyclical spending rule and the Chilean Central Bank aims to ensure price stability by targeting yearly inflation of around 3%. Chile has been successful in attracting foreign direct investment, and in 2011, achieved the second-highest foreign investment inflows in South America. Chile holds investment-grade sovereign debt ratings from all major ratings agencies, S&P, Fitch and Moody’s (AA-, A+, and Aa3, respectively). GeoPark 20F 109 Oil and gas industry Demand and consumption According to ENAP, national consumption of refined oil products reached 18.4 mmcf in Chile during 2012, a 0.4% increase compared to 2011 and equivalent to 316,200 barrels per day. This increase was mainly due to strong In 2012, the bulk of gas demand (41%) came from the power generation sector. Industry and the petrochemical sector accounted for 24% each, and the residential/commercial sector for the remaining 11%. Supply and production Chile is a large net importer of both crude oil and oil products. and stable economic growth, offset by an increase in prices of the main Its hydrocarbon reserves, which comprise limited crude oil reserves and products. As is the case in many OECD countries, oil is predominantly used as 1,447.9 bcf of natural gas reserves according to the OPEC Annual Statistical a transport fuel, but a notable difference in Chile is that diesel is used as a Bulletin 2013, or the OPEC Bulletin, are concentrated in the Magallanes substitute for natural gas in power generation. Basin at the southern tip of the country. Diesel is the main product in terms of consumption in Chile (157,300 Due to its limited oil and natural gas reserves, Chile has in the past imported barrels per day), followed by gasoline (66,300 barrels per day) and liquid almost all of its crude oil requirements principally from Brazil, Argentina petroleum gas, or LPG (36,200 barrels per day). Among the different and Colombia, and most of its natural gas requirements principally types of refined oil products, gasoline experienced the greatest increase in from Trinidad and Tobago, Argentina, Guinea and Yemen. In the northern terms of consumption, with consumption increasing 5.2% compared to 2011. part of the country, natural gas is imported through the Mejillones liquid natural gas, or LNG, terminal and is used predominantly for electricity % change generation by the mining industry. In the central part of the country from prior (including the capital, Santiago), gas is primarily supplied by the Quintero Consumption in Chile by type of oil product (thousands of cubic meters) Diesel Gasoline LPG Fuel Oil Kerosene Others Total 2012 9,153 3,856 2,109 1,498 1,243 542 2011 8,936 3,667 2,090 1,864 1,192 586 18,401 18,335 year 2.4% 5.2% 0.9% (19.6%) 4.3% (7.5%) 0.4% Source: ENAP 2012 Annual Report Natural gas consumption grew significantly from the late 1990s to 2004, as direct pipeline connections were built to Argentina, providing a cheap and easily accessible supply. In 2002, however, the Argentine government capped the price of gas in its domestic market, resulting in increased demand for natural gas in Argentina. This led the Argentine government in 2004 to restrict natural gas exports to Chile in order to reserve them for domestic use. 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 operate and in which we may operate in the future may adversely affect our business, financial condition and results of operations.” The restriction of Argentine natural gas exports has caused gas consumption in Chile to decrease significantly since 2004, when natural gas accounted for some 24% of the Total Primary Energy Supply, or TPES, according to the International Energy Agency. By 2009, natural gas only accounted for 8% of TPES. LNG terminal. 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 PERU Arica BOLIVIA BOLIVIA PERU Arica Tocopilla Mejillones Antofagasta Taltal Quintero Con Con Santiago Quintero Santiago Bio Bio Concepción AR GENTINA Concepción AR GENTINA CHILE Gregorio Punta Arenas Pemuco CHILE Punta Arenas LPG has been consumed in place of natural gas. As such, the LPG and gas but imported 174.8 mbopd of crude oil and 134.8 bcf of natural gas, In 2012, Chile produced 6.1 mbopd of crude oil and 40.2 bcf of natural gas markets overlap in Chile. LPG is predominantly used as a residential fuel in according to the OPEC Bulletin. Chile (notably for cooking), particularly in relatively remote regions. 110 GeoPark 20F 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. controlled mainly by ENAP, with few private companies working in this The Ministry of Energy is also responsible for the protection, conservation sector. We were the first private producer of oil and gas in Chile. and 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. of hydrocarbons may be carried out by the state, companies owned by the To enforce such regulations, the SDEC has the power to impose fines and, state or private persons through administrative concessions granted by if necessary, to take over the administration of deficient services when the President of Chile by Supreme Decree or CEOPs executed by the Minister applicable. Our operations 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 Service and Superintendency exploitation industry is supervised by the Chilean Ministry of Energy. of Environment The Ministry of Environment, the Environmental Assessment Service and In Chile, a participant is granted rights to explore and exploit certain assets the Superintendency of Environment are primarily responsible for under a CEOP. If a participant breaches certain obligations under a CEOP, the environmental issues in Chile, including those affecting the oil and gas participant may lose the right to exploit certain areas or may be required industry. The Ministry of Environment is responsible for the formulation to return all or a portion of the awarded areas to Chile with no right of and implementation of environmental policies, plans and programs, as well compensation. Although the government of Chile cannot unilaterally modify as for the protection and conservation of biological diversity and renewable the rights granted in the CEOP once it is signed, exploration and exploitation natural resources and water resources and for promoting sustainable are nonetheless subject to significant government regulations, such as development and the integrity of environmental policy and regulations. regulations concerning the environment, tort liability, health and safety and The Environmental Assessment Service is responsible for assessing whether labor. In the past year, for example, the Chilean government has proposed projects that might have an adverse effect on the environment comply with new regulations regarding the closure plans applicable to hydrocarbon Chilean environmental laws and regulations. The Environmental Assessment operations that could have an impact on the timeframes and costs required Service directs and coordinates the environmental impact assessment to set up exploration or exploitation activities. process, whose final qualification is granted by the competent regional environmental assessment commission. The Superintendency of Regulatory entities The Chilean Ministry of Energy and the National Commission of Energy Environment’s primary responsibilities are monitoring compliance with the terms of an environmental impact assessment, as well as monitoring (Comisión Nacional de Energía), or the CNE, are the principal government compliance with government plans to prevent environmental damage or to agencies responsible for the issuance of policies and regulations for the oil and gas sector. The Chilean Ministry of Energy is responsible for clean or restore contaminated geographical areas. The Superintendency of Environment has the power to suspend or terminate, or impose fines monitoring a participant’s compliance with its obligations under a CEOP. The from US$1,000 up to US$10.0 million for, activities that it deems to have an Superintendency of Electricity and Fuels (Superintendencia de Electricidad adverse environmental impact, even if such activities comply with a y Combustibles), or the SDEC, supervises compliance with regulations previously approved environmental impact assessment. regarding gas pipeline transportation and the Ministry of Environment, the Environmental Assessment Service and the Superintendency of Environment are responsible for environmental matters. The new Environmental The Environmental Courts The Environmental Courts are principally responsible for hearing appeals Courts are responsible for adjudicating claims against the Superintendency of determinations made by the Superintendency of Environment and of Environment and claims concerning environmental damage. for adjudicating claims for environmental damage. There is currently one Ministry of Energy The Chilean Ministry of Energy is responsible for developing and Environmental Court in Chile, which began to hear claims on December 28, 2012. Another two Environmental Courts are expected to begin hearing claims during 2013. The Environmental Court that will have jurisdiction over coordinating all plans, policies and regulations for the energy sector in Chile the area in which we operate elected its members on September 12, 2013 and supervising and advising the government in all matters related to and is expected to begin hearing claims shortly. energy. It coordinates the different entities in the energy sector in Chile and, GeoPark 20F 111 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 for Marketing, Operations and Transportation of Hydrocarbons Liquids— Constitution of the Republic of Chile and Decree with Law Force No 2 of 1986 Crude Oil, Liquefied Gas and Liquid Products of Petroleum and Natural Gas of the Ministry of Mines, which set forth the revised text of the Decree Law 1089 and the following international conventions: the International Convention of 1975, on CEOPS. However, the right to explore and develop fields is granted for the prevention of Pollution of the Sea by Oil of 1954, the Convention on for each area under a CEOP between Chile and the relevant contractors. the Prevention of Marine Pollution by Dumping of Wastes and Other Matters The CEOP establishes the legal framework for hydrocarbon activities, including, of 1972 and the International Convention on Civil Liability for Oil Pollution among other things, minimum investment commitments, exploration and Damage of 1969. exploitation phase durations, compensation for the private company (either in cash or in kind) and the applicable tax regime. Accordingly, all the provisions Taxation governing the exploitation and development of our Chilean operations are With regard to direct taxes on hydrocarbon exploitation, the general rule is contained in our CEOPs and the CEOPs constitute all the licenses that we need that hydrocarbons are transferred to the contractor (its retribution under the in order to own, operate, import and export any of the equipment used in our CEOP), and those re-acquisitions from the contractor performed by Chile or business and to conduct our gas and petroleum operations in Chile. its enterprises, as well as their corresponding acts, contracts and documents, are tax exempt. In addition, hydrocarbon exports by the contractor are also Under Chilean law, the surface landowners have no property rights over tax exempt. With regard to income taxes, as provided by article 5 of Decree the minerals found under the surface of their land. Subsurface rights do not Law No. 1,089, the contractor is subject either to a single tax calculated generate any surface rights, except the right to impose legal easements on its retribution, equal to 50% of such retribution, or to the general income or rights of way. Easements or rights of way can be individually negotiated tax regime established in the Income Tax Law (Decree Law No. 824 of with individual surface land owners or can be granted without the consent 1974), in force at the time of the execution of the public deed which contains of the landowner through judicial process. Pursuant to the Chilean Code CEOPs, terms of which will be applicable and invariable throughout the of Mines, a judge can permit a party to use an easement pending final duration of the contract. Income in Chile is subject to corporate tax on an adjudication and settlement of compensation for the affected landowner. accrual basis and has a current rate of 20%. The applicable and invariable Regulation of transportation activities Liquid hydrocarbon transportation, storage, importation and marketing are corporate income tax rates of our CEOPs range between 15% and 18.5%, as follows: the Fell Block is subject to a rate of 15%, the Otway and Tranquilo Blocks are subject to a rate of 17% and the Flamenco, Isla Norte and subject to a number of technical regulations regarding safety, quality and Campanario Blocks are subject to a rate of 18.5% for the income accrued other matters. The rules for the transportation of liquid fuels through or received during 2012 and 17% for the income accrued or received trucks and pipelines are primarily found in Supreme Decree No. 160 of 2009 during 2013 and onward. Dividends or profits distributed to the foreign (the Safety Code for Facilities and Production and Refining Operations, Transportation, Storage, Distribution and Supply of Liquid Fuels) of the shareholders of the contractors are subject to 35% Additional Withholding Tax with a tax credit for the corporate income tax paid by the contractor Ministry of Economy. The Ministry of Energy is responsible for the regulation being deductible from the corporate income tax already paid as credit. of transportation by pipeline and the Ministry of Transport is responsible With regard to the value added tax, contractors may obtain as a refund the for the regulation of transportation by truck. value added tax (which is 19% according to the Sales and Services Tax Gas transportation in Chile is subject to open access rules, in which the import or purchase of goods or services used in connection with the gas transportation company must make its excess transportation capacity exploration and exploitation activities. The applicable tax regime for each available to third parties under equal economic, commercial and technical CEOP remains unchanged throughout the duration of the CEOP. Law contained in Decree Law No. 825 of 1974) supported or paid on the conditions. Laws prohibit the abuse of a dominant position by a gas transportation company in order to discriminate among potential customers Colombia for use of its pipelines. Pursuant to Ministry of Economy Supreme Decree No. 280 of 2009, gas pipelines must also comply with the Regulation of Security for Transportation and Distribution of Gas, which regulates the Oil and gas industry Today, Colombia is one of the largest and most stable economies in South design, construction, operation, maintenance, inspection and termination America. The country has a stable political and judicial environment, with a of operations of a natural gas pipeline. strong track record of growth. Furthermore, Colombia holds investment- 112 GeoPark 20F grade sovereign debt ratings from all major rating agencies (BBB, BBB- and Colombia—production profile Baa3 from S&P, Fitch and Moody’s, respectively). . 1 3 2 2 . 9 8 1 2 . 3 5 1 2 . 9 8 0 2 . 9 5 2 2 . 5 4 0 2 . 5 6 3 2 . 1 3 0 2 . 4 4 0 2 . 1 7 4 22 5 0 2 . . 7 0 7 3 . 4 3 0 3 . 2 1 2 3 . 9 8 5 2 . 8 4 6 2 . 8 7 2 2 . 6 3 2 4 . 3 8 8 3 . 5 5 6 3 . 9 8 9 43 3 5 3 . In 2012, the country’s GDP grew by 4%, with CPI inflation at 2.44%. In order to stimulate growth and private investments, Colombia has throughout the last years entered into several free trade agreements, which include the agreement with the United States in May 2012 and the creation of the Pacific Alliance with Mexico, Peru and Chile in June 2013. Oil is currently Colombia’s leading export and source of foreign investment. 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 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Oil (mmboe) Natural Gas (bcf ) to be at risk of becoming a net oil importer unless significant additional Source: BP Statistical Review reserves were discovered. As a result, Ecopetrol was restructured, and in 2003, a regulatory agency for the sector, the ANH, was created. Following these Colombia is divided in 23 sedimentary basins. Colombian sedimentary basins initial steps, consistent acreage sales to private investors coupled with better have extensively developed petroleum systems that make them well suited seismic work led to an improvement in the country’s exploratory success for exploration and exploitation of hydrocarbons. Colombian supply growth rate and, consequently, to a change in the country’s production landscape. is driven mainly by conventional resources located in reservoirs with large Discoveries in Colombia in general have not been relevant in terms of regional distribution systems and heavy oil development along the eastern scale; however, the number of discoveries has favored a significant increase part of the Tertiary Foreland basins. The Eastern Llanos and Magdalena Valley in production and the creation of several medium-sized companies. Basins show the most potential for exploration activities. The Eastern Llanos Opportunities offered by the Colombian energy sector have changed the Basin accounts for over 79% of the country’s current oil and liquids reserves, competitive landscape by attracting foreign investment in the country from followed by Caguan-Putumayo Basin, which accounts for 9%. The Eastern leading multinational energy companies that operate in Colombia either Llanos Basin also contains large gas reserves, comprising 90% of the country’s independently or through joint ventures. Foreign investment in the oil and reserves. From 2002 to 2012, Colombian production increased at a CAGR of gas industry in Colombia has grown from US$1.125 million in 2005 to 5.1% for oil and 6.8% for natural gas. US$5.377 million in 2012. Colombia—signed contracts 64 59 59 54 44 76 54 32 28 32 21 7 8 We believe Colombia offers significant potential for value creation through the application of modern technology and exploration strategies on undercapitalized producing fields. Colombia—seismic profile (thousand km 2D equivalent) 26.5 26.0 24.0 20.1 16.3 18.2 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 E&P TEA Asociación (ECP) Source: ANH 11.9 10.0 6.8 3.5 1.4 2.4 2.1 According to the BP Statistical Review, Colombia is the third-largest producer of 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 crude oil and the seventh-largest producer of natural gas in Central and South Source: ANH America. According to the BP Statistical Review, in 2012, the country’s oil production reached 365.5 mmboe, with natural gas production of 423.6 bcf. GeoPark 20F 113 Regulation of the oil and gas industry Under Colombian law, the state owns all hydrocarbon reserves discovered ANLA The ANLA was created pursuant to Decree 3573 of 2011 issued by in the Colombian territory and exercises control of the exploitation of such the Colombian government with the participation of the Administrative reserves primarily through the ANH. Department of Public Functions (Departamento Adminstrativo de la Función Pública), and is responsible for hydrocarbon environmental licensing in The ANH is responsible for managing all exploration lands not subject Colombia. Any project in the hydrocarbons sector requiring an environmental to previously existing association contracts with Ecopetrol. The ANH began license must submit to environmental licensing procedures, which require offering all undeveloped and unlicensed exploration areas in the country the presentation of an environmental impact assessment, an environmental under E&P Contracts and Technical Evaluation Agreements, or TEAs, management plan and a contingency plan. Environmental licenses are which resulted in a significant increase in Colombian exploration activity granted for exploration and production phases separately. and competition, according to the ANH. According to the ANH, since January 2004, 450 E&P Contracts and 97 TEAs have been signed, of which 46 E&P Contracts and eight TEAs have been signed during 2012. The ANH is also CREG Laws 142 and 143 of 1994 created the CREG, a special administrative unit of in charge of negotiating and executing contracts through “direct negotiation” the Ministry of Mines and Energy, responsible for establishing the standards mechanisms with attention to special conditions in the areas to be explored. for the exploitation and use of energy, regulating the domestic utilities of Regulatory entities The principal authorities that regulate our activities in Colombia are the electricity and fuel gas (liquefied petroleum gas and natural gas), establishing price rules for energy and gas and regulating self-generation and cogeneration of energy. The CREG is also responsible for fostering the development of the Ministry of Mines and Energy, the ANH, the National Environmental Licensing energy services industry, promoting competition and responding to consumer Authority, or the ANLA, and the Regulatory Commission of Energy and Gas, and industry needs. Decree 4130 of 2011 assigned the CREG new functions or the CREG. that were previously fulfilled by the Ministry of Mines and Energy, including the regulation of tariffs for oil transportation in poliducts and the regulation of Ministry of Mines and Energy The Ministry of Mines and Energy is responsible for managing and regulating petroleum-derived liquid fluids. Colombia’s nonrenewable natural resources, assuring their optimal utilization by defining and adopting national policies regarding exploration, Superintendency of Domiciliary Public Services Under Colombian regulations, the distribution and marketing of natural production, transportation, refining, distribution and export of minerals gas is considered a public service. As such, this activity, as well as electricity, and hydrocarbons. are regulated by Law 142 of 1994 and supervised by the Superintendency of Domiciliary Public Services (Superintendencia de Servicios Públicos ANH The ANH was created in 2003 and is responsible for the administration Domiciliarios). of Colombia’s hydrocarbon reserves. The ANH’s objective is to manage the hydrocarbon reserves owned by the state through the design, promotion and negotiation of the exploration and production agreements in areas where hydrocarbons may be found. The ANH is also responsible for creating Regulatory framework Regulation of exploration and production activities Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon and maintaining attractive conditions for private investments in the resources located in Colombia and has full authority to determine the rights, hydrocarbon sector and for designing bidding rounds for exploration blocks. royalties or compensation to be paid by private investors for the exploration or Any oil company selected by the ANH to explore a specific block must the authority responsible for regulating all activities related to the exploration execute either a TEA or an E&P Contract to develop and exploit the block and production of hydrocarbons in Colombia. production of any hydrocarbon reserves. The Ministry of Mines and Energy is 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 Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, waiver to make royalty payments in cash or the specific contract provides establishes the general procedures and requirements that must be completed for payment in cash. Any oil company working in Colombia must present to by a private investor prior to commencing hydrocarbon exploration or the ANH periodic reports on the evolution of their exploration and production activities. The Petroleum Code sets forth general guidelines, exploitation activities. obligations and disclosure procedures that need to be followed during the performance of these activities. 114 GeoPark 20F Exploration and production activities were governed by Decree 1895 of system has ranged from 8% for fields producing up to 5,000 bopd to 25% 1973 until September 2009. Decree Law 2310 of 1974 (as complemented by for fields producing in excess of 600,000 bopd. Changes in royalty programs Decree 743 of 1975) governed the contracts and contracting processes only apply to new discoveries and do not alter fields already in their carried out by Ecopetrol and the rules applicable to such contracts, and also production stage. Producing fields pay royalties in accordance with the provided that Ecopetrol was responsible for administering the hydrocarbons applicable royalty program at the time of the discovery. The purchase price resources in the Country. Decree 2310 of 1974 was replaced by Decree is calculated based on a reference price for crude oil at the wellhead and Law 1760 of 2003, but all agreements entered into by us prior to 2003 with varies depending on prevailing international prices. Decree 2100 of 2011 other oil companies are still regulated by Decree 2310 of 1974. modified the commercialization scheme of natural gas royalties. From 2012 and until May 2013, producers had to directly commercialize the royalties Decree Law 1760 of 2003 provided the faculties, structure and functions of their own production on behalf of the ANH. In return, the ANH paid a of the ANH, and granted the ANH full and exclusive authority to regulate and commercialization fee to producers. As of May 2013, contractors must pay in oversee the exploration and production of hydrocarbon reserves. Decree kind royalties to third parties called “Royalty Trading Companies” or “Royalty Law 1760 of 2003 was complemented by Decree 2288 of 2004, which Marketing Companies,” which are in charge of commercializing the royalties. regulates all aspects related to the reversion of reserves and infrastructure under the joint venture agreements executed by us before 2004. Regulation of refining and petrochemical activities Refining and petrochemical activities are considered to be public utility The regime for the ANH’s contracts is set forth in Agreement 008 of 2004 and activities and are subject to governmental regulation. Article 58 of the Agreement 004 of 2012. Accord 008 of 2004, as repealed and replaced by Petroleum Code establishes that oil refining activities can be developed Accord 004 of 2012, issued by the Directive Council of the ANH, sets forth the throughout Colombia. Oil refineries must comply with the technical necessary steps for entering into E&P Contracts with the ANH. This characteristics and requirements established by the existing regulations. Agreement only regulates the contracts entered into as of May 4, 2012. Prior contracts are still ruled by Agreement 008 of 2004. The Ministry of Mines and Energy is responsible for regulating, supervising and overseeing all activities related to the refining of crude oil, import of Resolution 18-1495 of 2009 establishes a series of regulations regarding refined products, storage, transport and distribution. hydrocarbon exploration and exploitation. In the E&P Contracts, operators are afforded access to non-contracted blocks by committing to an exploration Decree 2657 of 1964 regulated the oil refining activities and created the Oil work program. These E&P Contracts provide companies with 100% of new Refining Planning Committee, which is responsible for studying industry production, less the participation of the ANH, which participation may differ problems and implementing short- and long-term refining planning policies. for each E&P Contract and depends on the percentage that each company The Committee is also responsible for evaluating and reviewing new refining has offered to the ANH in order to be granted with a block, subject to projects or expansion of existing infrastructure. In evaluating a new project, an initial royalty payment of 8% and the payment of income taxes of 33%. the Committee must take into account the significance of the project and the In addition, the Colombian government also introduced TEAs, in which companies that enter into TEAs are the only ones to have the right to explore, economic impact, the sources of financing, profitability, social contribution, the effects on Colombia’s balance of payments and the price structure of the evaluate and select desirable exploration areas and to propose work refined products. commitments on those areas, and have a preemptive right to enter into an E&P Contract, thereby providing companies with low-cost access to larger Pursuant to Resolution 18-0966 of 2006 issued by the Ministry of Mines and areas for preliminary evaluation prior to committing to broader exploration Energy and Article 58 of the Petroleum Code, any refining company operating programs. A preemptive right is granted to convert the TEA into an E&P in Colombia must provide a portion or, if needed, the total of its production Contract. Exploration activities can only be carried out by the TEA contractor. to supply local demand prior to exporting any production. If the regulated Pursuant to Colombian law, companies are obligated to pay a percentage lower than the export parity price, the price paid for the refined products of their production to the ANH as royalties and an economic right as ANH’s will be equivalent to the price for those products in the U.S. Gulf Coast participating interest in the production. In 1999, a modification to the royalty market. If there is local demand for imported crudes, the refining company system established a sliding scale for royalty payments, linking them to may charge additional transportation costs in proportion to the crudes production income, the principal item in the price formula, becomes the production level of crude oil and natural gas fields discovered after July delivered to the refinery. 29, 1999 and to the quality of the crude oil produced. Since 2002 the royalties GeoPark 20F 115 In 2008, Law 1205 was issued, with the main purpose of contributing to According to Law 681 of 2001, multipurpose pipelines must be open to a healthier environment, and established the minimum quality that fuels third-party use and owners must offer their capacity on the basis of equal should have in the country and the time frame for such a purpose. access to all. Hydrocarbon transport activity may be developed by third parties and must meet all requirements established by law. The Ministry of Mines and Energy establishes the safety standards for LPG, storage equipment, maintenance and distribution. Regulations issued in The Ministry of Mines and Energy is responsible for studying and approving 1992 established that every local, commercial and industrial facility with a the design and blueprints of all pipelines, mediation of rates between parties storage capacity of LPG greater than 420 pounds must receive authorization or, in case of disagreement, establishing the hydrocarbon transport rates for operations from the Ministry of Mines and Energy. based on information furnished by the service provider, issuing hydrocarbon As of May 2012, under the powers granted by Decree 4130 of 2011 for of transport-related taxes and managing the information system for the oil currency and tax matters as well as for royalties, the ANH will determine product distribution chain. transport regulations, liquidation, distribution and verification of payment the crude oil price reference. Regulation of transportation activities Hydrocarbon transportation activity is considered a public utility activity in Colombia and therefore is under governmental supervision and control. 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. It is also a public service, and pipelines are considered to be public transport Recently, further regulations on pipeline access and tariff systems have been companies. Transportation and distribution of crude oil, natural gas and defined by the Ministry of Mines and Energy. Over the past months, the refined products must comply with the Petroleum Code, the Commerce Code Ministry of Mines and Energy has been working on a project to modify the (Código de Comercio) and with all governmental decrees and resolutions. 2010 regulation of pipeline access and tariff systems. Notwithstanding the general rules for hydrocarbon transportation in Colombia, natural gas transportation has specific regulations, due to the Taxation The Tax Statute and Law 9 of 1991 provide the primary features of the oil categorization of natural gas distribution as a public utility activity under and gas industry’s tax and exchange system in Colombia. Generally, national Colombian laws. Therefore, natural gas distribution transportation is taxes under the general tax statute apply to all taxpayers, regardless of governed by specific regulation, issued by the CREG that seeks primarily industry. The main taxes currently in effect—after the December 2012 tax to satisfy the needs of the population. reform discussed below—are the income tax (25%), the special income tax for the development of social investments (9% for 2013 to 2015 and 8% The exportation of natural gas is not considered a public utility activity for 2016 and beyond) the equity or net assets tax, sales or value added under Colombian law and therefore is not subject to Law 142 of 1994. tax (16%), and the tax on financial transaction (0.4%). Additional regional Nevertheless, the internal supply of natural gas is a priority for the Colombian government. This policy is included in Decree 2100 of 2011, providing that taxes also apply. Colombia has entered into a number of international tax treaties to avoid double taxation and prevent tax evasion in matters of in the event the supply of natural gas is reduced or halted as a result of income tax and net asset tax. a shortage of this hydrocarbon, the Colombian government has the right to suspend the supply of natural gas to foreign customers. Notwithstanding Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the the foregoing, the Decree 2100 of 2011, establishes freedom to export natural international investment regime, regulates foreign capital investment in gas, under normal conditions for gas reserves. Colombia. Resolution 8 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions governing Transport systems, classified as crude oil pipelines and multipurpose exchange operations. Articles 48 to 52 of Resolution 8 provide for a special pipelines, can be owned by private parties. The building, operation and exchange regime for the oil industry that removes the obligation of maintenance of pipelines must comply with environmental, social, technical repayment to the foreign exchange market currency from foreign currency and economic requirements under national and international standards. sales made by foreign oil companies. Such companies may not acquire Transportation networks must follow specific conditions regarding design foreign currency in the exchange market under any circumstances and and specifications, while complying with the quality standards demanded must reinstate in the foreign exchange market the capital required in order by the oil and gas industry. to meet expenses in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by 116 GeoPark 20F informing the Colombian Central Bank, in which case they will be subject proven domestic oil and natural gas reserves from offshore sites contributed to the general exchange regime of Resolution 8 and may not be able to to 94% of total proven reserves (with the remainder located onshore). access the special exchange regime for a period of 10 years. Recent pre-salt discoveries are expected to be transformational for Brazil. On December 26, 2012, the Colombian Congress approved a number of The hydrocarbon fields Sapinhoá (former Guará), Lula (former Tupi), tax reforms. These changes include, among other things, VAT rate Iara, and Cernambi (former Iracema) have the vast majority of the recoverable consolidation, a reduction in corporate income tax (from 33% to 25%), volumes of 15.7 bboe announced by Petrobras in its Management and changes to transfer pricing rules, the creation of a new corporate income Business Plan for 2013-2017. On October 21, 2013 the ANP hosted an auction tax to pay for health, education and family care issues (9% for fiscal years of the Libra prospect in the Santos basin, which was discovered in 2010. 2013 to 2015 and 8% from 2016 and beyond), modifications in It was the first bidding of the production sharing regime. A consortium individual income tax, new “thin capitalization” rules and a reduction of formed by Petrobras, Shell, Total, China National Petroleum Corporation and social contributions paid by certain employees. The implementation China National Offshore Oil Corporation was awarded the concession, of such tax reforms requires further administrative regulation. As of the offering a 41.65% share of profit oil to the federal government (the minimum date of this annual report, some administrative regulations had been share of profit oil set forth under the bidding protocol). ANP studies estimate published, although we do not expect the final impact of these reforms to a potential of 26 to 42 billion barrels of oil in situ, of which 8 to 12 billion be material to our business. are recoverable barrels. Brazil Growth of oil and natural gas production (CAGR from 2002 to 2012) 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, 13.39% the country’s proved oil reserves in 2012 jumping to 15.3 bboe, an increase 5.81% of 1.8% as compared to the previous year. The reserves’ CAGR throughout 4.42% 3.96% 3.75% the last 10 years has reached 4.56%, significantly above the world’s average CAGR of 2.36%. Furthermore, production has also grown above the global rate during this 10-year period—3.7% as compared to 1.4%— in great part favored by recent discoveries in the pre-salt and offshore Atlantic concessions. In 2012, oil production reached 822.4 mmbbl. 2.99% 2.84% 2.78% 2.74% 2.69% 2.00% 2.00% 1.62% 0.70% -0.53% r a t a Q n a t s h k a z a K t i a w u K l i z a r B k a r I i a b a r A i d u a S s e t a r i m E b a r A d e t i n U a i r e g N i n a t s i n e m k r u T n a r I n a i s s u R n o i t a r e d e F S U a y b L i a d a n a C l a e u z e n e V Similar dynamics took place for the natural gas market, with reserves in 2012 jumping to 0.45 trillion cubic meters, or tm3, with an implied 10-year Source: BP Statistical Review CAGR of 6.50%, significantly above the global CAGR of 1.91%. Production Historically, Brazil’s oil and natural gas industry was controlled by Petrobras. has also grown above the global rate during this period—6.53% as compared In 1995, the Brazilian Federal Constitution was amended to allow to 2.90%—also favored by both non-associated gas finds and gas associated privately- or publiclyowned companies to engage in the exploration and with the pre-salt areas. In 2012, natural gas production reached 614.2 bcf. exploitation of oil and natural gas, subject to conditions set forth in specific Production levels will be further boosted with the next bidding round, legislation governing the sector. In 1997, the Brazilian Petroleum Law which has been pre-announced by the ANP for the fourth quarter of 2013, created the ANP to promote a transparent regulatory framework and bidding and which will be dedicated to areas with gas potential according to studies rounds for new concession areas and to regulate and oversee the Brazilian led by the ANP. oil and natural gas sector. Today, offshore fields are the main contributor to reserves and production; The opening of the Brazilian oil and natural gas industry attracted the however, the first phase of the production history in the sector, with attention of private companies. According to the ANP’s Brazilian Annual upstream activities dating back to the 1940s, was in the onshore space, Statistic Report of Petroleum, Natural Gas and Biofuelds, until the end with the Recôncavo Basin in northeast Brazil playing a pivotal role. In 2011, of year 2012 Brazil had 701 areas under concession, being 279 blocks under exploration phase, 75 fields under development and 347 fields under GeoPark 20F 117 production, with 133 concessionaries conducting exploratory, development account the increased local production and imports from Bolivia, natural gas and production activities in Brazilian sedimentary basis. Out of the 347 fields currently accounts for about 7.5% of total Brazilian energy demand, according currently in production, 278 were exclusive concessions to Petrobras and to the 2012 National Energy Balance published by the Energy Research 22 fields were designed as partnership agreements between Petrobras and Company, or EPE. Furthermore, according to EPE’s 2021 Ten Year Energy other concessionaries. Petrobras did not take part in the remaining 47. Expansion Plan, the share of natural gas in overall energy consumption As of December 2013, the ANP has held 12 oil and gas bidding rounds and further boosted with the next bid round, which has been pre-announced by one pre-salt auction. Round zero was the first round, and was held by the ANP for the fourth quarter of 2013, and which will be dedicated to areas the ANP to define Petrobras’s participation in its existing concessions after with gas potential according to studies led by the ANP. in Brazil should reach 7.8% in 2016 and 8.1% in 2021. Production will be the end of its monopoly. The graph below indicates the number of exploration concessions auctioned at each round. Brazil has the capacity for both sustained and rapid growth in natural gas The ANP’s exploratory concession grants 251 over the next decade, which may potentially change the balance between natural gas supply and demand in the country. The increased supply could open up new opportunities in the country. Natural gas may not only 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, become a seasonal exporter. 154 89 210 101 20 81 65 41 117 65 52 54 142 87 55 The increase of the gas supply associated with a growing reserve profile is expected to enable the continued development of the domestic market at rates above the historical ones. Market growth has been largely directed 72 by increased demand from the industrial and power generation sectors, which increased their demand for gas by 89.1% between 2002 and 2011, according to the EPE. 1 12 21 9 12 34 27 7 21 11 10 First (1999) Second (2000) Third (2001) Fourth (2002) Fifth (2003) Sixth (2004) Seventh (2005) Ninth (2007) Tenth (2008) Eleventh (2012) Libra Auction Twelfth (2013) The chart below compares the reserves with the reserves-to-production, Offshore Onshore or R/P, ratio, in Brazil in the periods indicated. Source: ANP Reserves versus R/P(1) (Brazil) On May 14, 2013, the ANP hosted the 11th oil and gas bidding round offering 289 concessions, located in 11 basins. These concessions cover approximately 155.8 sq. km. The auction was characterized by a high level of participation and raised R$2.8 billion in proceeds through license fees. Of the 289 concessions offered, 142 were successfully bid upon by industry players. 26 24 315.9 313.5 31 32 29 28 31 29 26 27 491.7 26 476.5 Additionally, on November 28, 2013, the ANP hosted the 12th oil and gas bidding round offering 240 concessions, located in seven onshore basins. 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 241 242 321 302 343 360 359 362 417 453 452 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Reserves (million cubic metres) R/P (years) bid upon by industry players. Source: BP Statistical Review Natural gas market in Brazil The natural gas industry in Brazil has undergone significant changes (1) R/P is a valuation formula, calculated as total proved reserves, or R, divided by annualized current net daily production, or P. over the past decade. During this period, natural gas was the fastest-growing The chart below illustrates the Brazilian domestic natural gas supply in the component of the non-renewable energy mix in the country. Taking into periods indicated. 118 GeoPark 20F Natural gas production/imports 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 5,369 5,055 8,086 8,998 9,789 10,334 11,348 8,366 12,647 10,481 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 15,525 15,792 16,971 17,699 17,706 18,152 21,593 21,137 22,938 24,064 demand. 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Production (mcm) Import (mcm) Source: ANP 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. Infrastructure and workforce Refineries There are currently 16 refineries operating in Brazil, of which 12 are Petrobras- operated. The current refining capacity is approximately 2.1 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 1.5 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, Overview. Extensive infrastructure is already in place in the mature coastal basins. The Brazilian midstream infrastructure has grown significantly during natural gas resources and other fluid hydrocarbon deposits, as well as over the refining, importation, exportation and sea or pipeline transportation recent years. However, it is still small in comparison to other countries, of crude oil and natural gas. Initially, paragraph one of article 177 barred the such as the U.S., China and France. In total, there are 32 oil pipes extending assignment or concession of any kind of involvement in the exploration of across 2,000 km. Local oil pipeline systems connect the fields in the Sergipe- oil or natural gas deposits to private industry. On November 9, 1995, however, Alagoas, Potiguar and Recôncavo Basins to the coastal export terminals Constitutional Amendment Number 9 altered paragraph one of article 177 where oil is sent by ship to the refineries in Fortaleza, Bahia and other States. so as to allow private or state-owned companies to engage in the exploration The Brazilian government is expected to announce a ten-year plan for and production of oil and natural gas, subject to the conditions to be set pipeline development, or Pemat, similar to what is done today in the power forth by legislation. and utilities sector, through EPE’s 2021 Ten Year Energy Expansion Plan. With a well-established onshore oil and gas industry, the country has an experienced and skilled workforce. Oil infrastructure. The oil infrastructure in Brazil is relatively limited, and the majority of oil production is offshore. Oil is loaded onto tankers and shipped The Brazilian Petroleum Law, which enacted this constitutional provision: • confirmed the Federal Government’s monopoly over oil and natural gas deposits and further provided that the exploration and production of such hydrocarbons would be regulated and overseen by the federal government; • created the CNPE (as defined below) and the ANP; • revoked Law Number 2,004/53, which appointed Petrobras as the exclusive directly to coastal terminals and refineries or exported. agent to execute the Federal Government’s monopoly; and • established a transitional rule that entitled Petrobras to: (1) produce in fields Gas infrastructure. The gas pipeline network in Brazil is still relatively underdeveloped despite the significant expansion currently underway. where Petrobras had already started production under a concession agreement made with the ANP for 27 years, on an exclusive basis, starting There are many gas transmission pipelines, including international pipelines on the date the field was declared commercially profitable; and (2) explore and a large distribution system. However, the existing infrastructure covers areas where Petrobras was able to show evidence of “established reserves” only a small portion of Brazil, primarily serving the main population centers prior to the enactment of the Brazilian Petroleum Law, for up to three years, of São Paulo and Rio de Janeiro, some states in the south and coastal subsequently extended to five years. states in the northeast. GeoPark 20F 119 Regulatory entities (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 National petroleum, natural gas and biofuel agency (ANP) The Brazilian Petroleum Law created the ANP. The ANP is a regulatory Alagoas). Our winning bids are subject to confirmation of qualification requirements. See “—Our operations— Operations in Brazil” and “Item 3. body of the federal government associated with the Ministry of Mines and Key information—D. Risk factors—Risks relating to our business— Energy. The ANP’s function is to regulate the oil, natural gas and biofuels The PN-T-597 concession is subject to an injunction and may not close” for industry in Brazil. One of the ANP’s primary objectives is to create a more information. competitive environment for oil and natural gas activities in Brazil that will lead to the lowest prices and best services for consumers. Its principal In order to participate in the auction process a company must have proven responsibilities include enforcing regulations as well as awarding concessions experience in oil and gas exploration and production activities, be legally related to oil, natural gas and biofuels, in accordance with the Brazilian constituted under the laws of their home country and undertake that, in the Petroleum Law, as set forth in Decree No. 2,455, dated January 14, 1998, event that they are successful in bidding, the company will constitute a and regulations enacted by the National Council on Energy Policy and company with its headquarters and management in Brazil, organized under National Interest. National council on energy policy (CNPE) The CNPE, also created by the Brazilian Petroleum Law, is a council of the President of Brazil presided over by the Minister of Mines and Energy. Brazilian law, and have the determined (specific for each bidding round) minimum net equity. If all requirements are met, the company will be considered qualified to bid and make offers for the bidding areas within its category. The CNPE is charged with submitting national energy policies, designing oil and natural gas production policies and establishing the procedural guidelines Environmental issues The identification and definition of the concessions to be offered is based for competitive bids regarding the exploration concessions and areas with on the availability of geological and geophysical data indicating the presence established viability in accordance with the Brazilian Petroleum Law. of hydrocarbons. Also, in order to protect the environment, the ANP, the Regulatory framework IBAMA and the state environmental agencies analyze all the areas prior to deciding which concessions to offer in licensing rounds. The requirement levels for environmental licensing for the various concessions to be Pricing policy Until the enactment of the Brazilian Petroleum Law, the Brazilian government auctioned are then published, allowing the future concessionaire to include environmental considerations in determining what projects to pursue. regulated all aspects of the pricing of oil and oil products in Brazil, from These environmental guidelines are revised and updated with every ANP the cost of oil imported for use in refineries to the price of refined oil products bidding round. charged to the consumer. Under the rules adopted following the Brazilian Petroleum Law, the Brazilian government changed its price regulation policies. Under these regulations, the Brazilian government: (1) introduced a new methodology for determining the price of oil products designed to Consortium The oil and natural gas industry is characterized in Brazil by the presence of several companies acting through consortium agreements, or unincorporated track prevailing international prices denominated in U.S. dollars, and (2) joint ventures, in order to share the risks of exploration, development and gradually eliminated controls on wholesale prices. production activities. Terms of those agreements are set out by the ANP and the actual risk sharing agreement is reflected in joint operating agreements. Concessions In addition to opening the Brazilian oil and natural gas industry to private investment, the Brazilian Petroleum Law created new institutions, including the ANP, to regulate and control activities in the sector. As part of this Taxation Introduction. The Brazilian Petroleum Law introduced significant modifications and benefits to the taxation of oil and natural gas activities. mandate, the ANP is responsible for licensing concession rights for the The main component of petroleum taxation is the government take, exploration, development and production of oil and natural gas in Brazil’s comprised of license fees, fees payable in connection with the occupation sedimentary basins through a transparent and competitive bidding process. or title of areas, royalties and a special participation fee. The introduction of The ANP has conducted 12 bidding rounds for exploration concessions the Brazilian Petroleum Law presents certain tax benefits primarily with since 1999. Most recently, in November 2013, the twelfth round was respect to indirect taxes. Such indirect taxes are very complex and can add conducted; 240 blocks in 13 sectors of seven basins were offered, of which significantly to project costs. Direct taxes are mainly corporate income 72 were awarded. Of these 72 blocks, we were awarded two new concessions tax and social contribution on net profit. 120 GeoPark 20F Government take. With the effectiveness of the Brazilian Petroleum Law and the regulations promulgated by the ANP, concessionaires are required with applicable legal requirements. The period in which the goods are allowed to remain in Brazil under the REPETRO regime may vary depending to pay the Brazilian federal government the following: on the importer, but usually corresponds to the duration of the contract • license fees; executed between the Brazilian company and the foreign entity, or the period • rent for the occupation or retention of areas; for which the company was authorized to exploit or produce oil and gas. • special participation fee; and • royalties on production. In 2007, the legislation regarding the State Value Added Tax—ICMS imposed taxation on the import of equipment into Brazil under the REPETRO The minimum value of the license fees is established in the bidding rules for regime was significantly changed by ICMS Convention No. 130/2007. This the concessions, and the amount is based on the assessment of the potential, regulation allows each State to grant the ICMS tax calculation basis reduction as conducted by the ANP. The license fees must be paid upon the execution (generating a tax burden of 7.5% with the recoverability of credits or 3%, of the concession contract. Additionally, concessionaires are required to pay a without the recoverability of credits) for goods purchased under the REPETRO rental fee to landowners varying from 0.5% to 1.0% of the respective regime for the production phase and the total exemption or ICMS tax hydrocarbon production. calculation basis reduction (generating a tax burden of 1.5%, without the recoverability of credits) for the exploration phase. In order to be in force, The special participation fee is an extraordinary charge that concessionaires the ICMS Convention No. 130/07 must be included in each state’s legislation. must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable For example, currently, based on Convention No. 130/2007 , the state of 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 on which extraordinary production occurs. This participation rate, whenever (generating a tax burden of 7.5%, with the recoverability of credits or 3%, due, may reach up to 40% of net revenues depending on (i) volume of without the recoverability of credits) and production of oil and gas production and (ii) whether the block is onshore, shallow water or deep (generating a tax burden of 1.5%, without the recoverability of credits). water. Under the Brazilian Petroleum Law and applicable regulations issued For production activities, the legislation used to grant an exemption of ICMS, by the ANP, the special participation fee is calculated based upon quarterly which was recently changed to a tax calculation basis reduction, according net revenues of each field, which consist of gross revenues calculated using to Resolution Sefaz No. 631, dated May 14th, 2013. reference prices published by the ANP (reflecting international prices and the exchange rate for the period) less: • royalties paid; • investment in exploration; • operational costs; and It is important to mention that before the enactment of the Convention No. 130/2007, the State of Rio de Janeiro has attempted to impose ICMS on production activities, based on State Law No. 4,117, dated June, 27, 2003, which was regulated by Decree No. 34,761, dated February 3, 2004, and • depreciation adjustments and applicable taxes. was subsequently suspended by Decree No. 34,783 of February 4, 2004 for The ANP is responsible for determining monthly minimum prices for 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 petroleum produced in concessions for purposes of royalties payable with this law is currently being challenged by the Public Ministry in the Supreme respect to production. Royalties generally correspond to a percentage Court (ADI 3,019-RJ). ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and Pursuant to the Brazilian Petroleum Law and subsequent legislation, the concession agreement. In determining the percentage of royalties applicable federal government enacted Law No. 10,336/01, to impose the Contribution to a particular concession, the ANP takes into consideration, among other for Intervention in the Economic Sector, or CIDE, an excise tax payable by factors, the geological risks involved and the production levels expected. producers, blenders and importers on transactions with some of oil and fuel Relevant Tax Aspects on Upstream Activities. The special customs regime for goods to be used in the oil and gas activities in Brazil, REPETRO, aims primarily at reducing the tax burden on companies involved in exploring and extracting oil and natural gas, through the total suspension of federal taxes due on the importation of equipment (platforms, subsea equipment, among others), under leasing agreements, subject to the compliance 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. GeoPark 20F 121 Argentina Oil and gas industry Argentina is the second-largest producer of natural gas and the fourth- largest producer of crude oil in Central and South America, according to the BP Statistical Review. The country is a leading producer and consumer of natural gas in South America, and has a globally significant unconventional oil and gas resource base. Production of both oil and natural gas throughout the last years has been dropping as a result of the maturing of the production fields and lack of investment. In 2012, the country’s natural gas production reached 1331 bcf, with oil production at 242.4 mmbbl. 3.9 3.7 4.0 3.3 2.9 4.2 4.3 4.2 4.2 4.6 4.4 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Billion cubic feet per day In response to the economic crisis of 2001 and 2002, the Argentine government, pursuant to the Public Emergency Law (Law No. 25,561), Source: BP Statistical Review established export taxes on certain hydrocarbon products. In subsequent years, in order to satisfy growing domestic demand and abate inflationary Driven by economic expansion and stable domestic prices, energy pressures, this law was supplemented by constraints on domestic prices, consumption has increased significantly from 2002 to 2012, with demand for export restrictions and subsidies on imports of natural gas and diesel, among oil and gas increasing from 331.7 mboe in 2002 to 518.9 mboe in 2012. other measures. As a result, local prices for oil and natural gas products Argentine natural oil and gas consumption grew at a CAGR of approximately had remained significantly below those prevalent in neighboring countries 4.6% during this period, according to the BP Statistical Review. In recent years, and international commodity exchanges. demand has outpaced energy supply (in 2012, the deficit reached 42.5 mboe). After declining during the economic crisis of 2001 and 2002, Argentina’s the country’s production surplus has shifted toward a deficit. Still, according real gross domestic product, or GDP, grew at a compounded average to the BP Statistical Review, Argentina’s R/P ratio is at 10.2x. growth rate, or CAGR, of 8.4% from 2003 to 2008. Although the growth rate decelerated to 0.9% in 2009 as a result of the global financial crisis, it Argentina’s production of oil and natural gas (mmboe) As a result of this increasing demand and the maturing of local reserves recovered in 2010 and 2011, growing at an annual rate of 9.2% and 8.9%, respectively, according to the International Monetary Fund. In 2012, the GDP 554.2 584.2 596.2 589.8 591.0 574.2 558.5 528.8 513.8 491.7 476.5 growth rate dropped to 1.9% as a reflex of the Brazilian slowdown spillover effect over to its regional trading partners, especially Argentina, Paraguay, and Uruguay. In Argentina, widespread import and exchange controls also affected business confidence and investment. 315.9 313.5 300.1 288.8 286.8 278.4 267.8 255.8 249.3 235.8 227.6 Argentina’s consumption of oil and natural gas 238.2 270.7 296.1 301.0 304.1 295.7 290.7 273.0 264.5 255.9 248.9 523 534 522 557 598 612 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 394 405 425 449 471 Oil Natural Gas Source: BP Statistical Review 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Thousand barrels daily Regulation of the oil and gas industry Under Argentine law, the federal executive branch establishes the federal policy applicable to the exploration, exploitation, refining, transportation and marketing of liquid hydrocarbons, but the licensing and enforcement of exploration and production activities has been transferred from the federal government to provincial governments. 122 GeoPark 20F Regulatory entities The principal authorities that regulate the activities in Argentina are the Decrees passed during 1989 relating to free marketability of hydrocarbons at negotiated prices, the deregulation of the oil and gas industry, Secretariat of Energy and the Strategic Planning and Coordination Committee freedom to import and export hydrocarbons and the ability to keep for the National Hydrocarbon Investment Plan, at the federal level, and a proceeds from export sales in foreign bank accounts. The repeal of these local enforcement authority at each province (typically a secretariat of energy articles appears to formalize certain rules such as price controls and or hydrocarbons board). the repatriation of export sales proceeds, which has been in fact required by the government over the last several years. Regulatory framework From the 1920s to 1989, the Argentine public sector dominated the upstream In addition, the decree created the Strategic Planning and Coordination segment of the Argentine oil and gas industry and the midstream and Committee for the National Hydrocarbon Investment Plan, charged with downstream segment of the business. developing investment plans for the country to increase production and reserves and to make Argentina more energy self-sufficient. The decree In 1989, Argentina enacted certain laws aimed at privatizing the majority of also requires oil and gas companies, refiners and transporters of hydrocarbon its state-owned companies and issued a series of presidential decrees products to submit annual investment plans for approval by the commission. (namely, Decrees No. 1055/89, 1212/89 and 1589/89, or the Oil Deregulation The decree empowers the commission to issue fines and sanctions, Decrees, relating specifically to deregulation of energy activities). The Oil including concession termination, for companies that do not comply with Deregulation Decrees eliminated restrictions on imports and exports its requirements. Finally, the Strategic Planning and Coordination Committee of crude oil, deregulated the domestic oil industry, and effective January 1, for the National Hydrocarbon Investment Plan is also charged with the 1991, the prices of oil and petroleum products were also deregulated. responsibility of assuring the reasonableness of hydrocarbon prices in the In 1992, Law No. 24,145, referred to as the Privatization Law, privatized YPF domestic market and that such prices allow companies to generate a and provided for transfer of hydrocarbon reservoirs from the Argentine reasonable profit margin. government to the provinces, subject to the existing rights of the holders of exploration permits and production concessions. Domain and Jurisdiction of hydrocarbons resources After a constitutional reform enacted in 1994, eminent domain over In October 2004, the Argentine Congress enacted Law No. 25,943, creating hydrocarbon resources lying in the territory of a provincial state is now a new state-owned energy company, Energía Argentina S.A., or ENARSA. vested in such provincial state, while eminent domain over hydrocarbon The corporate purpose of ENARSA is the exploration and exploitation of resources lying offshore on the continental platform beyond the solid, liquid and gaseous hydrocarbons; the transport, storage, distribution, jurisdiction of the coastal provincial states is vested in the federal state. commercialization and industrialization of these products; as well as the transportation and distribution of natural gas, and the generation, Thus, oil and gas exploration permits and exploitation concessions are now transportation, distribution and sale of electricity. Moreover, Law No. 25,943 granted by each provincial government. A majority of the existing granted ENARSA all offshore areas located beyond 12 nautical miles from the coastline up to the outer boundary of the continental shelf that were concessions were granted by the federal government prior to the enactment of Law No. 26,197 and were thereafter transferred to the provincial states. vacant at the time of the effectiveness of this law (i.e., November 3, 2004). On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty Regulation of exploration and production activities The Argentine oil and gas industry is regulated by Law No. 17,319, referred Act. This law declared achieving self-sufficiency in the supply of hydrocarbons, to as the Hydrocarbons Law, which was adopted in 1967 and amended as well as in the exploitation, industrialization, transportation and sale of by Law No. 26,197 in 2007, which established the general legal framework hydrocarbons, a national public interest and a priority for Argentina. In addition, for the exploration and production of oil and gas. In turn, Law No. 24,076, the law expropriated 51% of the share capital of YPF, the largest Argentine oil referred to as the Natural Gas Law, enacted in 1992, established the company, from Repsol, the largest Spanish oil company. regulatory framework for natural gas transportation and distribution utilities and the trading of natural gas. In addition, certain concurrent hydrocarbons On July 28, 2012, Presidential Decree 1277/2012, which regulated the laws were enacted by some provincial states. In Argentina, eminent domain Hydrocarbon Sovereignty Law, was released, establishing that the Strategic over hydrocarbon resources lying in the territory of a provincial state is Planning and Coordination Committee for the National Hydrocarbon now vested in such provincial state, while eminent domain over hydrocarbon Investment Plan must be in charge of the sector’s reference prices. The resources lying offshore on the continental platform beyond the jurisdiction decree introduced important changes to the rules governing Argentina’s of the coastal provincial states is vested in the federal state. oil and gas industry. The decree repeals certain articles of Deregulation GeoPark 20F 123 The Hydrocarbons Law authorizes the granting of hydrocarbon exploration byproducts were capped or regulated. A series of other measures was also permits made up of up to 3 exploration sub-periods for an aggregate term adopted, affecting the downstream segment of the industry. not exceeding 9 years (for onshore blocks) and 12 years (for offshore blocks) plus certain extensions. The relinquishment of 50% of the exploration acreage at the end of each exploration sub-period is mandatory. Upon a Regulation of transportation activities Exploitation concessionaires have the exclusive right to obtain a commercial discovery, the holder of such exploration permits is entitled transportation concession for the transport of oil and gas from the provincial to apply for and obtain an exploitation concession to exploit such discovery states or the federal government, depending on the applicable jurisdiction. for a term of 25 years. Such exploitation concession can be extended for Such transportation concessions include storage, ports, pipelines and an additional term of 10 years as part of a concession renegotiation process other fixed facilities necessary for the transportation of oil, gas and by- with the incumbent provincial states. Article 59 of the Hydrocarbons Law products. Transportation facilities with surplus capacity must transport third provides that the concessionaire shall pay to the state a monthly royalty parties’ hydrocarbons on an open-access basis, for a fee which is the same of 12% of the net production of liquid and gaseous hydrocarbons at the well for all users on similar terms. As a result of the privatizations of YPF and Gas head, which may be reduced to as low as 5% depending on the productivity, del Estado, a few common carriers of crude oil and natural gas were conditions and locations of the wells. Royalties are generally paid in chartered and continue to operate to date. cash at the same price received by the producer at the well head, unless the government gives proper notice of its intention to receive payment in kind. Also, past the initial 25-year term of a concession, an incremental Taxation Exploitation concessionaires are subject to the general federal and provincial royalty is generally required by the incumbent provincial state as part of tax regime. The most relevant federal taxes are the income tax (35%), the the renegotiation to grant the 10-year extension to a concession. value added tax (21%) and a tax on assets. The most relevant provincial taxes Because individual provinces are in charge of licensing and overseeing the are the turnover tax (1% to 3%) and stamp tax. In 2002, in response to the exploration and exploitation process, there is some variance between economic crisis, the federal government adopted new taxes on oil and gas individual provinces in terms of the regulations and royalty requirements products, including export taxes ranging from 5% for by-products to 45% for for concessionaires. Holders of exploration permits and exploitation crude oil. Despite that, under certain incentives programs established in concessions must also pay an annual surface fee that is based on acreage 2008 (namely, the Oil Plus Program and the Refining Plus Program created by of land held and which varies depending on the phase (exploration or Presidential Decree 2014/2008), oil and gas companies increasing their oil production) of the operation. reserves and production and refining companies increasing their production would be granted tax rebate certificates to be credited against the payment Regulation of refining and petrochemical activities Refining and petrochemical activities in Argentina have historically been of the export taxes. However, the Oil Plus Program and the Refining Plus Program were suspended for certain companies in February 2012 and governed by free enterprise and private refineries have coexisted with state- subsequently amended and reinstated in June 2012. owned refineries. Until 1989, crude oil production, whether extracted by YPF or by private Certain tax benefits apply to exploration programs in association with ENARSA. Also, certain foreign exchange and regulatory benefits apply to companies operating under service contracts, was delivered to YPF, and the E&P programs in association with YPF qualifying for such benefits. Argentina Secretariat of Energy distributed the same among the refining companies has also implemented certain tax incentives to promote infrastructure according to quotas. Natural gas production was until then also delivered to and capital goods investments, including oil and gas production and YPF and to the then existing stateowned Gas del Estado SE utility company. transportation, including advanced reimbursement of value added tax and accelerated income tax depreciation. 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. After the economic crisis of 2001 and 2002, hydrocarbons refiners and producers were prompted by the Argentine Government to enter into a series of tripartite agreements whereby the prices of crude oil and certain 124 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 the date of this annual report. 99.9% 99.9% 100% 100% 99.9% GeoPark Limited (Bermuda) GeoPark Colombia Coöperatie U.A. (Netherlands) 1% GeoPark Latin America Limited – Bermuda (Bermuda) 100% GeoPark Latin America Limited Agencia en Chile (Chile) GeoPark Argentina Limited – Bermuda (Bermuda) 100% GeoPark Argentina Limited - Argentinean Branch (Argentina) GeoPark Latin America Coöperatie U.A. (Netherlands) 80% GeoPark Colombia Coöperatie U.A. (Netherlands) 20% LG International GeoPark Brazil Coöperatie U.A. (Netherlands) 99.9% GeoPark Brazil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) 99.9% Rio Das Contas Produtora de Petróleo Ltda. (Brazil) 80% 99.9% 100% 80% 100% LG International 20% GeoPark Chile S.A. (Chile) GeoPark S.A. (Chile) GeoPark Brazil SpA. (Chile) GeoPark Colombia S.A. (Chile) GeoPark Colombia SAS (Colombia) 14% 86% 100% 99% GeoPark TdF S.A. (Chile) GeoPark Fell SpA. (Chile) GeoPark Magallanes Limitada (Chile) 99.9% Servicios Southern Cross Limitada (Chile) D. Property, plant and equipment See “—B. Business Overview—Title to properties”. Bermuda Companies Chilean Companies Argentinean Companies Colombian Companies Brazilean Companies Netherlands Companies GeoPark 20F 125 ITEM 4A. UNRESOLVED STAFF COMMENTS Not applicable. ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS A. Operating results The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and Argentina, respectively) for the year 2013, consisting of US$133.3 million related to exploration, including approximately 1,350 sq. km. in 3D seismic surveys (more than 1,100 in Chile, mainly related to the blocks located in Tierra del Fuego and over 250 in Colombia). In March 2014 we invested US$140 million in Brazil, subject to certain adjustments, to acquire Rio das Contas, which we financed through the incurrence of a loan of US$70.5 million and cash on hand. and the notes thereto, the Rio das Contas Financial Statements included In 2014, we expect our total capital expenditures, excluding the purchase elsewhere in this annual report, as well as the information presented under price for our Rio das Contas acquisition, to be between US$220 million to “Item 3. Key Information—A. Selected financial data” and “Item 3. Key US$250 million, of which approximately 62%, 32% and 5% will be in Chile, Information—A. Selected financial data—Unaudited Condensed Combined Colombia and Brazil, respectively. These capital expenditures will include the Pro Forma Financial Data.” drilling of 50 to 60 new wells (approximately 40% of which we expect will be exploratory wells), as well as workovers, seismic surveys and new facility The following discussion contains forward-looking statements that involve construction. In Brazil, we expect our capital expenditures will consist risks and uncertainties. Our actual results may differ materially from those of between US$5 million to US$7.5 million to finance in part the construction discussed in the forward-looking statements as a result of various factors, of a gas compression plant in the Manatí Field we acquired as part of the including those set forth in “Item 3. Key Information—D. Risk factors” and Rio das Contas acquisition and approximately US$0.45 million in license “Forward-looking statements.” fee payments to the ANP relating to our Round 12 concessions, with the remainder for seismic surveys in exploration blocks in the Potiguar Factors affecting our results of operations We describe below the year-to-year comparisons of our historical results and Recôncavo Basins. and the analysis of our financial condition. Our future results could Our results of operations will be adversely affected in the event that our differ materially from our historical results due to a variety of factors, estimated oil and natural gas asset base does not result in additional reserves including the following: that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access Discovery and exploitation of reserves Our results of operations depend on our level of success in finding, acquiring to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, (including through bidding rounds) or gaining access to oil and natural our anticipated reserves will continually decrease, which would have a material gas reserves. While we have geological reports evaluating certain proved, adverse effect on our business, results of operations and financial condition. contingent and prospective resources in our blocks, there is no assurance that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural gas. The calculation of our Oil and gas revenue and international prices Our revenues are derived from the sale of our oil and natural gas production, geological and petrophysical estimates is complex and imprecise, and it is as well as of condensate derived from the production of natural gas. possible that our future exploration will not result in additional discoveries, Our oil and natural gas prices are driven by the international prices of oil and, even if we are able to successfully make such discoveries, there is no and methanol (for our Chilean gas production), respectively, which are certainty that the discoveries will be commercially viable to produce. We have denominated in U.S. dollars. The price realized for the oil we produce is been able to successfully develop our assets through drilling, with 70%, or linked to WTI and Brent, U.S. dollar denominated international benchmarks. 106, of the 152 exploratory, appraisal and development wells that we drilled The price realized for the natural gas we produce in Chile is linked to the from January 1, 2006 through December 31, 2013 becoming productive wells. international price of methanol, which is settled in the international markets in U.S. dollars. The market price of these commodities is subject to significant For the year ended December 31, 2013, we drilled 39 new wells 17 in Chile fluctuation and has historically fluctuated widely in response to relatively and 22 in Colombia) in blocks in which we have working interests and/or minor changes in the global supply and demand for oil and natural gas, economic interests. We made total capital expenditures of US$228.0 million market uncertainty, economic conditions and a variety of additional factors. (US$145.7 million, US$82.1 million and US$0.2 million in Chile, Colombia 126 GeoPark 20F For example, from January 1, 2010 to December 31, 2013, NYMEX WTI constant, after-tax profit for the year ended December 31, 2013 would have crude oil contracts prices ranged from a low of US$64.78 per bbl to a high of been lower by US$21.2 million (US$18.8 million in 2012). US$113.39 per bbl, Henry Hub natural gas average monthly spot prices ranged from a low of US$1.82 per mmbtu to a high of US$7.51 per mmbtu, In Brazil, prices for gas produced in the Manatí Field are based on a long-term US Gulf methanol spot barge prices ranged from a low of US$324.61 per off-take contract with Petrobras. For the year ended December 31, 2013, Rio metric ton to a high of US$530.71 per metric ton and Brent spot prices ranged das Contas’s average sale price was US$38.2/boe. The price of gas sold under from a low of US$67.18 per barrel to a high of US$128.14 per barrel. We have this contract is denominated in reais and is adjusted annually for inflation historically not hedged our production to protect against fluctuations in the pursuant to the Brazilian General Market Price Index (Índice Geral de Preços— international oil prices. Mercado), or IGPM. 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 WTI minus Production costs Our production costs consist primarily of expenses associated with the certain marketing and quality discounts based on, among other things, API production of oil and gas, the most significant of which are gas plant leasing, and mercury content. Mercury content can vary depending on the geology facilities and wells maintenance (including pulling works), labor costs, and features in each field. For the years ended December 31, 2013 and 2012, contractor and consultant fees, chemical analysis, royalties and products, these discounts resulted in average price deductions of US$13.11 per bbl among others. As commodity prices increase, our production costs may and US$9.35 per bbl, respectively, and realized prices of US$84.3 per bbl and increase. We have historically not hedged our costs to protect against US$85.4 per bbl, respectively. Furthermore, the price formula also considers fluctuations. adjustments for differences between the WTI and Brent at certain price levels. We have a long-term gas supply contract with Methanex. The price of the gas Availability and reliability of infrastructure Our business depends on the availability and reliability of operating and sold under this contract is determined based on a formula that takes into transportation infrastructure in the areas in which we operate. Prices and account various international prices of methanol, including US Gulf methanol availability for equipment and infrastructure, and the maintenance thereof, spot barge prices, methanol spot Rotterdam prices and spot prices in Asia. affect our ability to make the investments necessary to operate our business, See “Item 3. Key Information—D. Risk factors—Risks relating to our and thus our results of operations and financial condition. See “Item 3. Key business—A substantial or extended decline in oil, natural gas and methanol Information—D. Risk factors—Risks relating to our business—Our inability prices may materially adversely affect our business, financial condition or to access needed equipment and infrastructure in a timely manner may results of operations.” As of the date of this annual report, we had not entered hinder our access to oil and natural gas markets and generate significant into any derivative arrangements or contracts to mitigate the impact on our incremental costs or delays in our oil and natural gas production.” results of operations of fluctuations in commodity prices. In order to mitigate the risk of unavailability of operating and transportation 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, infrastructure, we have invested in the construction of plant and pipeline infrastructure to produce, process and store hydrocarbon reserves and to sulfur, delivery point and water content, as well as on certain transportation transport them to market. In the Fell Block, for example, we have constructed costs (including pipeline costs and trucking costs). The delivery points for our over 120 km of pipeline and a gas plant with a processing and compression production range from the well head to the port of export (Coveñas), depend capacity of 35.3 mmcfpd. We also constructed an oil treatment plant with a on the client: if sales are made via pipeline, the delivery point is usually processing capacity of 9,500 bopd to service oil produced in the Fell Block, the pipeline injection point, whereas for direct export sales, the most frequent which became operative in November 2013 and which, following a test period, delivery point is the well head . As a result, our average realized price for the we expect will be operated at full capacity by the end of November 2014. year ended December 31, 2013 was US$80.3 per bbl. Our oil sales 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. Production levels Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and, to a lesser extent, oil and natural gas prices. Since being awarded 100% of the working interest in the Fell Block in 2006, and through If the market prices of WTI, Brent and methanol had fallen by 10% as December 31, 2013, we have drilled 95 exploratory, appraisal and development compared to actual prices during the year, with all other variables held wells in the Fell Block, with 73%, or 69, of such wells becoming productive. GeoPark 20F 127 Production at the Fell Block has increased from 3,292 boepd in 2008 to 6,962 administrative costs to increase as a result of our Brazil Acquisitions, and boepd as of December 31, 2013. Since acquiring our Colombian operations and as a result of becoming a publicly traded company in the United States. Public through December 31, 2013, 46 exploratory, appraisal and development wells company costs include expenses associated with our annual and quarterly have been drilled in blocks in which we have working interests and/or reporting, investor relations, registrar and transfer agent fees, incremental economic interests, with 70% of such wells becoming productive. Production insurance costs and accounting and legal services. in our Colombian operations has increased from 2,965 boepd for the month of April 30, 2012 (the first full month following our Colombian acquisitions) to 6,491 boepd for the year ended December 31, 2013. Acquisitions Our results of operations are significantly affected by our past acquisitions. We generally incorporate our acquired business into our results of operations We expect that fluctuations in our financial condition and results of at or around the date of closing, such as our Colombian acquisitions in 2012 operations will be driven by the rate at which production volumes from and our recently acquired Rio das Contas (which we closed on March 31, our wells decline. As initial reservoir pressures are depleted, oil and gas 2014), which limits the comparability of the period including such production from a given well will decline over time. See “Item 3. Key acquisitions with prior periods. See “Item 3. Key Information—A. Selected Information—D. Risk factors—Risks relating to our business—Unless we financial data—Unaudited Condensed Combined Pro Forma Financial Data” replace our oil and natural gas reserves, our reserves and production for a pro forma analysis of our financial condition and results of operations. will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified As described above, part of our strategy is to acquire and consolidate assets locations in which we drill in the future may not yield oil or natural gas in in Latin America. We intend to continue to selectively acquire companies, commercial quantities.” producing properties and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results Contractual obligations In order to protect our exploration and production rights in our license areas, of operations difficult. We may also incur substantial debt, issue additional equity securities or use other funding sources to fund future acquisitions. we must make and declare discoveries within certain time periods specified in our various special contracts, E&P Contracts and concession agreements. The costs to maintain or operate our license areas may fluctuate or increase Functional and presentational currency Our Consolidated Financial Statements are presented in U.S. dollars, which significantly, and we may not be able to meet our commitments under is our functional and presentational currency. Items included in the financial these agreements on commercially reasonable terms or at all, which may information of each of our entities are measured using the currency of the force us to forfeit our interests in such areas. If we do not succeed in renewing primary economic environment in which the entity operates, or the functional these agreements, or in securing new ones, our ability to grow our business currency, which is the U.S. dollar in each case, except for our Brazil operations, may be materially impaired. See “Item 3. Key Information—D. Risk factors— including our recent Rio das Contas acquisition, where the functional Risks relating to our business—Under the terms of some of our various currency is the real. CEOPs, E&P Contracts and concession agreements, we are obligated to drill wells, declare any discoveries and file periodic reports in order to retain our rights and establish development areas. Failure to meet these obligations Geographical segment reporting We divide our business into four geographical segments—Chile, Colombia, may result in the loss of our interests in the undeveloped parts of our blocks Brazil and Argentina—that correspond to our principal jurisdictions of or concession areas.” operation. Activities not falling into these four geographical segments are reported under a separate corporate segment that primarily includes Administrative costs Our administrative costs increased by US$10.6 million, or 59%, from 2011 to certain corporate administrative costs not attributable to another segment. As of December 31, 2013, our Chilean segment contributed US$157.5 million, 2012, a significant portion of which was attributable to our acquisitions of or 46.5%, of our revenues, our Colombian segment contributed US$179.3 Winchester, Luna and Cuerva in the first quarter of 2012. Our administrative million, or 53.0%, of our revenues and our Argentine segment contributed costs for the year ended December 31, 2013 increased by US$17.8 million, US$1.5 million, or 0.5%, of our revenues. On a pro forma basis, our or 61.8%, compared to the year ended December 31, 2012. This increase was Brazil Acquisitions represented 12.5% of our revenues for the year ended primarily due to (i) higher corporate expenses related to our growth strategy December 31, 2013. and new business efforts, (2) increased staff costs in Colombia, and (iii) the start-up of our operations in Tierra del Fuego, Chile. Furthermore, we expect 128 GeoPark 20F In the description of our results of operations that follow, our “Other” operations reflect our non-Chilean and non-Colombian operations, primarily Administrative costs Administrative costs consist of corporate costs such as director fees and consisting of our Argentine, Brazilian (mainly related to the start-up of our travel expenses, new project evaluations and back-office expenses principally operations in such country) and corporate head office operations. comprised of wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions. Description of principal line items The following is a brief description of the principal line items of our statement of income. Selling expenses Selling expenses consist primarily of transportation and storage costs. 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. of value-added tax, or VAT, and discounts related to the sale (such as API and Financial income includes interest received from bank time deposits and mercury adjustments) and overriding royalties due to the ex-owners of oil the effect of exchange rate differences. Financial expenses principally include and gas properties where the royalty arrangements represent a retained interest expense not subject to capitalization, bank charges, the effect working interest in the property. Revenue is recognized when the significant of exchange rate differences and the unwinding of long-term liabilities. risks and rewards of ownership have been transferred to the buyer, the associated costs and amount of revenue can be estimated reliably, recovery of the consideration is probable, and there is no continuing management Profit for the period attributable to owners of the Company Profit for the period attributable to owners of the Company consists of profit involvement with the goods. for the year less non-controlling interest. Production costs For a description of our production costs, see “—Factors affecting our results 2014 Drilling and Work Program In March 2014, we invested US$140 million in Brazil, subject to certain of operations.” adjustments, to acquire Rio das Contas, which we financed through the incurrence of a loan of US$70.5 million and cash on hand. Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, In 2014, we expect our total capital expenditures, excluding the purchase based on commercial proved and probable reserves as calculated under price for our Rio das Contas acquisition, to be between US$220 million to the Petroleum Resources Management System methodology promulgated US$250 million. These capital expenditures will include the drilling of a total by the Society of Petroleum Engineers and the World Petroleum Council, 50 to 60 new wells (approximately 40% of which we expect will be or the PRMS, which differs from SEC reporting guidelines pursuant to which exploratory wells), as well as workovers, seismic surveys and new facility certain information in the forepart of this annual report is presented. construction. We expect that approximately 62% of our total capital The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves expenditures for 2014 will be incurred in Chile, which will include the drilling of approximately 32 to 37 wells, as well as workovers, seismic surveys and and cost estimates are recognized prospectively. Reserves are converted to new facility construction, including oil pipelines. We expect that equivalent units on the basis of approximate relative energy content. approximately 32% of our total capital expenditures for 2014 will be incurred Exploration costs Exploration costs consist of geosciences costs, including wages and salaries in Colombia, which will include the drilling of approximately 18 to 23 wells, as well as workovers and new facility construction, mainly related to civic works, production facilities in the Tua and Tigana fields and improvements and share-based compensation not subject to capitalization, impairment to the Taro Taro and Max field facilities. Finally, we expect that approximately losses, write-offs of unsuccessful exploration efforts, geological consultancy 5% of our total capital expenditures for 2014 will be incurred in Brazil, costs and costs relating to independent reservoir engineer studies. In which will consist of between US$5 million to US$7.5 million to finance in particular, upon completion of the evaluation phase, a prospect is either part the construction of a gas compression plant in the Manatí Field transferred to oil and gas properties if it contains reserves, or is charged as after the Rio das Contas acquisition and approximately US$0.45 million in exploration costs in the period in which the determination is made. See “— license fee payments to the ANP relating to our Round 12 concessions, Critical accounting policies and estimates—Oil and gas accounting.” with the remainder for seismic surveys in exploration blocks in the Potiguar and Recôncavo Basins. GeoPark 20F 129 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, Cash flow estimates for impairment assessments Cash flow estimates for impairment assessments require assumptions about as adopted by the IASB. The preparation of the financial statements requires two primary elements: future prices and reserves. Estimates of future prices us to make judgments, estimates and assumptions that affect the reported require significant judgments about highly uncertain future events. amounts of assets, liabilities, revenue and expenses, and related disclosure Historically, oil and natural gas prices have exhibited significant volatility. of contingent assets and liabilities. We continually evaluate these estimates Our forecasts for oil and natural gas revenues are based on prices derived and assumptions based on the most recently available information, our own from future price forecasts among industry analysts, as well as our own historical experience and various other assumptions that we believe to be assessments. Estimates of future cash flows are generally based on reasonable under the circumstances. Since the use of estimates is an integral assumptions of long-term prices and operating and development costs. component of the financial reporting process, actual results could differ from those estimates. The process of estimating reserves requires significant judgments and decisions based on available geological, geophysical, engineering and An accounting policy is considered critical if it requires an accounting economic data. The estimation of economically recoverable oil and natural estimate to be made based on assumptions about matters that are highly gas reserves and related future net cash flows was performed based uncertain at the time such estimate is made, and if different accounting on the D&M Reserves Report. Such estimates incorporate many factors and estimates that reasonably could have been used, or changes in the assumptions including: accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following • expected reservoir characteristics based on geological, geophysical and accounting policies represent critical accounting policies as they involve a engineering assessments; higher degree of judgment and complexity in their application and require • future production rates based on historical performance and expected us to make significant accounting estimates. The following descriptions future operating and investment activities; of critical accounting policies and estimates should be read in conjunction • future oil and natural gas prices and quality differentials; with our Consolidated Financial Statements and the accompanying notes • anticipated effects of regulation by governmental agencies; and and other disclosures included elsewhere in this annual report. • future development and operating costs. Business combinations Business combinations are accounted for using the acquisition method. Our management believes these factors and assumptions are reasonable based on the information available at the time we prepare our estimates. The cost of an acquisition is measured as the fair market value of the assets However, these estimates may change substantially as additional data acquired, equity instruments issued and liabilities incurred or assumed on from ongoing development activities and production performance becomes the date of completion of the acquisition. Acquisition costs incurred are available and as economic conditions impacting oil and natural gas prices expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination and costs change. are measured initially at their fair market values at the acquisition date. The excess of the cost of acquisitions over fair market value of a company’s share Oil and gas accounting Oil and gas exploration and production activities are accounted for in of the identifiable net assets acquired is recorded as goodwill. If the cost accordance with the successful efforts method on a field by field basis. We of the acquisition is less than a company’s share of the net assets required, account for exploration and evaluation activities in accordance with IFRS 6, the difference is recognized directly in the statement of income. Exploration for and Evaluation of Mineral Resources, capitalizing exploration The determination of fair value of identifiable acquired assets and assumed the underlying resources is determined. Costs incurred prior to obtaining liabilities means that we are to make estimates and use valuation techniques, legal rights to explore are expensed immediately to the income statement. and evaluation costs until such time as the economic viability of producing including independent appraisers. The valuation assumptions underlying each of these valuation methods are based on available updated information, Exploration and evaluation costs may include: license acquisition, geological including discount rates, estimated cash flows, market risk rates and other and geophysical studies (i.e., seismic), direct labor costs and drilling data. As a result, the process of identification and the related determination costs of exploratory wells. No depreciation and/or amortization are charged of fair values require complex judgments and significant estimates. during the exploration and evaluation phase. Upon completion of the 130 GeoPark 20F evaluation phase, the prospects are either transferred to oil and gas assumptions and judgments because most of the obligations will be settled properties or charged to expense (exploration costs) in the period in which after many years. Technologies and costs are constantly changing, as are the determination is made, depending whether they have found reserves. political, environmental, health, safety and public relations considerations. If not developed, exploration and evaluation assets are written off after Consequently, the timing and future cost of dismantling and abandonment three years, unless it can be clearly demonstrated that the carrying value of are subject to significant modification. Any change in the variables underlying the investment is recoverable. All field development costs are considered our assumptions and estimates can have a significant effect on the liability construction in progress until they are finished and capitalized within oil and and the related capitalized asset and future charges related to the retirement gas properties, and are subject to depreciation once complete. Such costs obligations. The present value of future costs necessary for well plugging and may include the acquisition and installation of production facilities, abandonment is calculated for each area on the basis of cash flows development drilling costs (including dry holes, service wells and seismic discounted at an average interest rate applicable to our company’s surveys for development purposes), project-related engineering and the indebtedness. The liability recognized is based upon estimated future acquisition costs of rights and concessions related to proved properties. abandonment costs, wells subject to abandonment, time to abandonment, Workovers of wells made to develop reserves and/or increase production are capitalized as development costs. Maintenance costs are charged to income when incurred. and future inflation rates. Share-based payments We provide several equity-settled, share-based compensation plans to certain employees and third-party contractors, composed of payments in the form Capitalized costs of proved oil and gas properties and production facilities of share awards and stock options plans. and machinery are depreciated on a licensed area by licensed area basis, using the unit of production method, based on commercial proved and Fair value of the stock option plans for employee or contractor services probable reserves. The calculation of the “unit of production” depreciation received in exchange for the grant of the options is recognized as an expense. takes into account estimated future finding and development costs, and The total amount to be expensed over the vesting period, which is the is based on current year-end unescalated price levels. Changes in reserves period over which all specified vesting conditions are to be satisfied, is and cost estimates are recognized prospectively. Reserves are converted determined by reference to the fair value of the options granted calculated to equivalent units on the basis of approximate relative energy content. using the Black-Scholes model. Determining the total value of our share- based payments requires the use of highly subjective assumptions, including Oil and gas reserves for purposes of our Audited Consolidated Financial the expected life of the stock options, estimated forfeitures and the price Statements are determined in accordance with PRMS, and were estimated volatility of the underlying shares. The assumptions used in calculating the by D&M, independent reserves engineers. fair value of share-based payment represent management’s best estimates, but these estimates involve inherent uncertainties and the application of Depreciation of the remaining property, plant and equipment assets management’s judgment. (i.e., furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight line method by applying such Non-market vesting conditions are included in assumptions in respect of annual rates as required to write-off their value at the end of their estimated the number of options that are expected to vest. At each balance sheet date, useful lives. The useful lives range between three and 10 years. we revise our estimates of the number of options that are expected to vest. Asset retirement obligations Obligations related to the plugging and abandonment of wells once We recognize the impact of the revision to original estimates, if any, in the statement of income, with a corresponding adjustment to equity. operations are terminated may result in the recognition of significant The fair value of the share awards payments is determined at the grant date liabilities. We record the fair value of the liability for asset retirement by reference of the market value of the shares and recognized as an expense obligations in the period in which the wells are drilled. When the liability over the vesting period. is initially recognized, the cost is also capitalized by increasing the carrying amount of the related asset. Over time, the liability is accreted to its When options are exercised, we issue new common shares. The proceeds present value at each reporting date, and the capitalized cost is depreciated received net of any directly attributable transaction costs are credited over the estimated useful life of the related asset. Estimating the future to share capital (nominal value) and share premium when the options are abandonment costs is difficult and requires management to make exercised. GeoPark 20F 131 Taxation The computation of our income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by us, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Revenue Net oil sales Net gas sales In addition, we have tax-loss carry-forwards in certain taxing jurisdictions that Net revenue are available to offset against future taxable profit. However, deferred tax Production costs assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. Gross profit Gross margin (%)(1) Exploration costs Administrative costs To the extent that actual outcomes differ from management’s estimates, Selling expenses taxation charges or credits may arise in future periods. Other operating income/(expense) Recent accounting pronouncements See note 2.1.1 to our Consolidated Financial Statements beginning on page 178 to this annual report. 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 Consolidated Financial Statements and the accompanying notes included 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 elsewhere in this annual report. Profit for the year attributable to We acquired Winchester and Luna on February 14, 2012 and Cuerva on March 27, 2012. Accordingly, our results for the year ended December 31, owners of the Company Net production volumes Oil (mbbl) 2013 and 2012 are not fully comparable with prior periods. For accounting Gas (mcf) purposes, the results of operations of Winchester, Luna and Cuerva were Total net production (mboe) For the year ended % Change December 31, from prior 2013 2012 year (in thousands of US$, except for percentages) 315,435 22,918 338,353 (179,643) 221,564 28,914 250,478 (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% 22,012 11,879 85% 4,056 5,263 4,933 2,513 8,346 3,904 consolidated into our financial statements beginning on January 31, 2012, Average net production (boepd) 13,517 11,292 January 31, 2012 and March 31, 2012, respectively. See Note 34 to our Annual Consolidated Financial Statements. In addition, our Consolidated Financial Statements will not be fully comparable with our consolidated financial statements prepared for any period following the date upon which we fully consolidate Rio das Contas into our operations for accounting purposes, which will occur in the second quarter of 2014. See “Presentation of Financial and Other Information.” Average realized sales price Oil (US$ per bbl) Gas (US$ per mmcf) Average unit costs per boe (US$) Operating cost Royalties and other Production costs(2) Depreciation Total production cost Year ended December 31, 2013 compared to year ended December 31, 2012 Exploration costs Administrative costs The following table summarizes certain of our financial and operating data for Selling expenses the years ended December 31, 2013 and 2012. 81.9 5.0 19.0 3.5 22.5 13.9 36.4 3.3 9.4 3.5 90.5 4.0 16.8 2.9 19.7 13.4 33.1 7.1 7.4 6.3 (1) Gross margin is defined as total revenue minus production costs, divided by total revenue. (2) Calculated pursuant to FASB ASC 932. 132 GeoPark 20F 61% (37)% 26% 20% (10)% 25% 13% 21% 14% 4% 10% (54)% 27% (44)% The following table summarizes certain financial and operating data. Net revenue Gross profit/(loss) Depreciation Impairment and write-off Chile Colombia Other 157,491 89,906 (30,471) (7,704) 179,324 67,612 (39,406) (3,258) 1,538 1,192 (323) — 2013 Total 338,353 158,710 (70,200) (10,962) For the year ended December 31, Chile Colombia Other 2012 Total 149,927 84,133 (28,734) (18,490) 99,501 39,304 (21,050) (5,147) (in thousands of US$) 1,050 (2,194) (3,533) (1,915) 250,478 121,243 (53,317) (25,552) Net revenue 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 natural gas sales from the year ended December 31, 2012 to the year ended December 31, 2013. For the year ended December 31, 2013 2012 (in thousands of US$) 315,435 22,918 221,564 28,914 338,353 250,478 Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) 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% Consolidated Sale of crude oil Sale of gas Total By country Chile Colombia Other Total GeoPark 20F 133 Net revenue increased 35%, from US$250.5 million for the year ended compared to the same period in 2012, and (ii) the development of the December 31, 2012 to US$338.4 million for the year ended December 31, Max and Tua fields and our discoveries of the Tarotaro field in the Llanos 34 2013, primarily as a result of an increase in volumes of crude sales by 55%. Block and the Potrillo field in the Yamú Block. This was partially offset by Sales of crude oil in operated blocks increased to 3,800 mbbl in the year a decrease in the average realized prices per barrel of crude oil from US$97.1 ended December 31, 2013 compared to 2,448 mbbl in the year ended per barrel to US$80.3 per barrel, primarily due to the fact that in 2013 we December 31, 2012, and resulted in net revenue of US$315.4 million for the started selling part of our oil production at well-head with higher commercial year ended December 31, 2013 compared to US$221.6 million for the year discounts, as opposed to transporting it to different delivery points, which ended December 31, 2012, partially offset by decreases in sales of gas from led to lower selling expenses that offset the lower selling prices. US$28.9 million for the year ended December 31, 2012 to US$22.9 million for the year ended December 31, 2013. Production costs The following table summarizes our production costs for the years ended The increase in 2013 net revenue of US$87.8 is mainly explained by: December 31, 2013 and 2012. • an increase of US$79.8 million in oil sales in Colombia • an increase of US$13.6 million in oil sales in Chile, partially offset by a decrease of US$6.0 million in gas deliveries in Chile. Net revenue attributable to our operations in Chile for the year ended December 31, 2013 was US$157.5 million, a 5% increase from US$149.9 million for the year ended December 31, 2012, principally due to (1) increased For the year ended % Change from prior December 31, 2013 2012 year (in thousands of US$, except for percentages) Consolidated (including Chile, Colombia and Argentina) sales of crude oil of 1,592 mbbl for the year ended December 31, 2013 Depreciation compared to 1,415 mbbl for the year ended December 31, 2012 (an increase Royalties of 12.5%) due to the continuing development in the Tobifera formation, and Staff costs (2) decreased average realized prices per barrel of crude oil from US$85.4 per Transportation costs barrel for the year December 31, 2012 to US$84.3 per barrel for the year Well and facilities maintenance ended December 31, 2013 (a decrease of US$1.1 per barrel or a total of 1.3%). Consumables The decrease in the average realized price per barrel was partly attributable Equipment rental to quality discounts in the year ended December 31, 2013 as compared to the Other costs (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) same period in 2012. The net increased sales of crude oil were partially offset Total (179,643) (129,235) 31% 51% 0% 58% 120% 50% 20% 35% 39% by a US$6.0 million reduction in gas sales mainly 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 December 31, 2013 was US$179.3 million, compared to US$99.5 million for the year ended December 31, 2012, representing 53% and 40% of our total By country Depreciation consolidated sales. Such amounts were primarily due to increased sales Royalties of crude oil in operated blocks, from 1,087 mbbl for the year ended December Staff costs 31, 2012 to 2,185 mbbl for the year ended December 31, 2013, an increase Transportation costs of 101%. This increase resulted from (i) the incorporation of an additional Well and facilities three months of Cuerva’s results in the year ended December 31, 2013 and maintenance the incorporation of an additional month of Winchester and Luna’s Consumables operations (the revenues for the corresponding period that were not included Equipment rental in the year ended December 31, 2012 amounted to US$23.8 million) as Other costs 2013 Colombia Chile Year ended December 31, 2012 Colombia Chile (in thousands of US$) (29,287) (39,233) (28,120) (20,964) (7,384) (6,508) (6,456) (8,163) (1,891) — (7,896) (9,661) (8,988) (4,733) (12,105) (12,886) (7,139) (16,967) (7,088) (8,560) (5,986) (6,290) (2,717) — (4,164) (7,432) (1,045) (2,850) (7,090) (5,936) (7,033) (10,716) Total (67,585) (111,712) (65,794) (60,197) 134 GeoPark 20F Production costs increased 39%, from US$129.2 million for the year ended Chilean operations. As a result, gross margin for the year ended December 31, December 31, 2012 to US$179.6 million for the year ended December 31, 2013 was 47%, which represented a slight decrease of 3% as compared to 2013, primarily due to the addition of US$51.5 million in such costs from our the gross margin for the year ended December 31, 2012. Gross profit per boe Colombian operations. increased 4%, to US$32.2 per barrel for the year ended December 31, 2013. In our Chilean operations, production costs increased by 2.7%, due to Gross profit attributable to our operations in Chile for the year ended the change in revenue mix from gas to oil, which has higher production costs December 31, 2012 was US$89.9 million, a 7% increase from US$84.1 million than gas, and due to an increase in our oil production. In the year ended for the year ended December 31, 2012. The contribution to our gross profit December 31, 2013, in Chile, operating costs per boe increased to US$12.2 during such years from our operations in Chile was 57% and 69%, per boe from US$10.7 per boe in 2012. In the year ended December 31, 2013, respectively. 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. Gross profit attributable to our operations in Colombia for the year ended December 31, 2012 was US$67.6 million a 72% increase from US$39.3 million Operating costs in Colombia increased 79.1%, to US$62.8 million for the year for the year ended December 31, 2012. The contribution to our gross profit ended December 31, 2013 as compared to the year ended December 31, during such years from our operations in Colombia was 43% and 32%, 2012, primarily due to an increase in production and deliveries the region and respectively. also 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 Exploration costs month of Winchester and Luna’s operations in Colombia (operating costs for the corresponding period that were not included in the year ended 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$34.0 per boe for the year ended December 31, 2012, due to the fact that increased production generated improved fixed Chile cost absorption, which positively impacted the production costs per boe. Colombia Other Total Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) (9,758) (3,341) (3,155) (20,452) (5,528) (1,910) 10,694 2,187 1,245 (16,254) (27,890) 11,636 (52)% (40%) 65% (42)% Gross profit Chile Colombia Other Total Year ended December 31, Change from prior year Exploration costs decreased 42%, from US$27.9 million for the year ended 2013 2012 % December 31, 2012 to US$16.3 million for the year ended December 31, 2013, (in thousands of US$, except for percentages) 7% 84,133 5,773 89,906 primarily as the result of the decrease in recognition of write-offs of unsuccessful efforts in an amount of US$14.6 million. 67,612 1,192 39,304 (2,194) 158,710 121,243 28,308 3,386 37,467 72% 154% The 2013 charge in write-off of unsuccessful efforts corresponds to the cost 31% of five unsuccessful exploratory wells: two in Chile (one in Fell Block and one in Tranquilo Block) and three in Colombia (one well in Cuerva Block and Gross profit increased 31%, from US$121.2 million for the year ended one well in each of the non-operated blocks, Arrendajo and Llanos 32). The December 31, 2012 to US$158.7 million for the year ended December 31, 2012 charge in write-off of unsuccessful efforts corresponds to the costs 2013, as a result of (i) increased sales and production in Colombia, (ii) the of eight unsuccessful exploratory wells: five in Chile (two in Fell Block, two in incorporation of an additional three months of Cuerva’s results in the year Otway Block and the remaining in Tranquilo Block) and three in Colombia ended December 31, 2013 and the incorporation of an additional month (one well in Cuerva Block, one well in Arrendajo Block and the remaining in of Winchester and Luna’s operations in Colombia (gross profit for the Llanos 17 Block). The 2012 charge also includes the loss generated by the corresponding period that was not included in the year ended December 31, relinquishment of an area in the Del Mosquito Block in Argentina. 2012 amounted to US$9.4 million) and (iii) increased net revenues in our GeoPark 20F 135 Administrative costs Operating profit (loss) Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) Chile Colombia Other Total (16,420) (16,409) (13,755) (10,879) (7,393) (10,526) (46,584) (28,798) (5,541) (9,016) (3,229) 17,786 51% Chile 121% Colombia 31% 62% Other Total Year ended December 31, Change from prior year 2013 2012 % (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% Administrative costs increased 62%, from US$28.8 million for the year ended We recorded an operating profit of US$84.0 million for the year ended December 31, 2012 to US$46.6 million for the year ended December 31, 2013, December 31, 2013, a 106% increase from US$40.8 million for the year ended primarily as a result of an increase in costs in: (1) our Chilean operations, December 31, 2012, primarily due to the incorporation of an additional three from US$10.9 million in the year ended December 31,2012 to US$16.4 million months of Cuerva’s results and an increase in production and deliveries in the year ended December 31, 2013, mainly due to the startup of our in Colombia in the year ended December 31, 2013 and the incorporation of operations in Tierra del Fuego; (2) increased staff and other costs in Colombia, an additional month of Winchester and Luna’s operations in Colombia. In and (3) higher corporate expenses related to our growth strategy and new addition, during the year ended December 31, 2013, in Chile, we recognized a business efforts. Selling expenses Chile Colombia Other Total gain amounting to US$3.2 million in other operating income related to the reversal of certain provisions previously recorded that, based on the view of our management and legal advisors, were extinguished as the statute of limitations was reached. Year ended December 31, Change from prior year 2013 2012 % Financial results, net Financial loss increased 108% to US$33.9 million, due to the accelerated (in thousands of US$, except for percentages) amortization of debt issuance costs incurred in connection with the (4,062) (12,677) (513) (5,327) (18,953) (351) (17,252) (24,631) 1,265 6,276 162 7,379 (24)% (33)% (46)% 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 (30)% 31, 2013 and the incorporation of an additional month of Winchester and Luna’s operations in Colombia into our results and higher interest expenses Selling expenses decreased 30%, from US$24.6 million for year ended December 31, 2012 to US$17.3 million for the year ended December 31, 2013, generated by the issuance of the Notes due 2020 in an amount of US$12.1 million, partially offset by interest income due to increased cash and cash primarily due to the change in the delivery point for certain of our production equivalents. in our Colombian operations. In our Chilean operations, selling expenses were 24% lower compared to prior year, primarily as a result of the impact of the DOP penalty we paid to Methanex in 2012, described in “— Business— Marketing and Delivery Commitments,” partially offset by the increase in oil deliveries in Chile. 136 GeoPark 20F Profit before income tax Profit for the year Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) Chile Colombia Other Total 49,965 31,049 (30,926) 50,088 42,272 11,223 (20,655) 32,840 7,693 19,826 (10,271) 17,248 18% Chile 177% Colombia 50% 53% Other 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% For the year ended December 31, 2013, we recorded a profit before income For the year ended December 31, 2013, we recorded a profit of US$34.9 tax of US$50.1 million, an increase of 53% from US$32.8 million for the year million, a 89% increase from US$18.5 million for the year ended December 31, ended December 31, 2012, primarily due to the incorporation of an additional 2012, as a result of the reasons described above. 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 into our results and to increases in production and Profit for the year attributable to owners of the Company Profit for the year attributable to owners of the Company increased by deliveries in Colombia, and, to a lesser extent, higher profits from our Chilean 85% to US$22.0 million, for the reasons described above. Profit attributable operations, partially offset by the occurrence of two non-recurring events: to non-controlling interest increased by 97% to US$12.9 million for the (1) accelerated amortization of debt issuance costs described above; year ended December 31, 2013 as compared to the prior year due to and (2) the comparative effect of a bargain purchase gain on acquisition of the incorporation of an additional three months of Cuerva’s results in the subsidiaries of US$8.4 million as a result of the acquisitions of Winchester year ended December 31, 2013 and the incorporation of an additional month and Luna recorded in the year ended December 31, 2012. of Winchester and Luna’s operations in Colombia and an increase in non-controlling interest resulting from LGI’s acquisition of a 20% equity interest in our Colombian operations. Income tax Chile Colombia Other Total Year ended December 31, Change from prior year 2013 2012 % (in thousands of US$, except for percentages) (4,121) (17,870) 6,837 (11,349) (4,976) 1,931 (15,154) (14,394) 7,228 (12,894) 4,906 (760) (64)% 259% 254% 5% Income tax increased 5%, from US$14.4 million for the year ended December 31, 2012 to US$15.2 million for the year ended December 31, 2013, as a result of our increased results of operations in Chile and Colombia. Our effective tax rate for the year ended December 31, 2013 was 30% as compared to 44% in the year ended December 31, 2012 due to lower charges from deferred income taxes in the year ended December 31, 2013 mainly resulting from the effect of currency translation on tax base in Colombia and Chile, compensated by an increase in current taxes resulting from higher profits in Chile and Colombia and the impact of tax loss carry forwards recorded in Colombia. GeoPark 20F 137 Year ended December 31, 2012 compared to year ended December 31, 2011 The following table summarizes certain of our financial and operating data for For the year ended % Change December 31, from 2013 2012 prior year the years ended December 31, 2012 and 2011. (in thousands of US$, 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 221,564 28,914 250,478 (129,235) 121,243 48% (27,890) (28,798) (24,631) 823 40,747 892 73,508 38,072 111,580 (54,513) 57,067 51% (10,066) (18,169) (2,546) (502) 25,784 162 (17,200) (13,678) 8,401 32,840 (14,394) 18,446 6,567 — 12,268 (7,206) 5,062 5,008 201% (24)% 124% 137% 112% (3)% 177% 59% 867% 264% 58% 451% 26% — 168% 100% 264% 31% Profit for the year attributable to owners of the Company 11,879 54 21,898% 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$) Operating cost Royalties and other Production costs(2) Depreciation Total production cost Exploration costs Administrative costs Selling expenses 2,513 8,346 3,904 11,292 916 11,135 2,771 7,593 90.5 4.0 16.8 2.9 19.7 13.4 33.1 7.1 7.4 6.3 83.8 3.9 8.6 1.7 10.3 9.3 19.7 3.6 6.6 0.9 174% (25)% 41% 49% 8% 2% 95% 71% 91% 44% 68% 97% 12% 600% (1) Gross margin is defined as total revenue minus production costs, divided by total revenue. (2) Calculated pursuant to FASB ASC 932. 138 GeoPark 20F The following table summarizes certain financial and operating data. Net revenue Gross profit/(loss) Depreciation Impairment and write-off Chile Colombia Other 149,927 84,133 (28,734) (18,490) 99,501 39,304 (21,050) (5,147) 1,050 (2,194) (3,533) (1,915) 2012 Total 250,478 121,243 (53,317) (25,552) For the year ended December 31, Chile Colombia Other 2011 Total 110,103 56,888 (25,297) (5,919) (in thousands of US$) 1,477 179 (1,111) (1,344) 111,580 57,067 (26,408) (7,263) — — — — Net revenue For the year ended December 31, 2012, crude oil sales were our principal resulted in net revenue of US$221.6 million for the year ended December 31, 2012 compared to US$73.5 million for the year ended December 31, 2011, source of revenue, with 88% and 12% of our total revenue from crude oil and partially offset by decreases in sales of gas from US$38.1 million for the year gas sales, respectively. The following chart shows the increase in oil and ended December 31, 2011 to US$28.9 million for the year ended December natural gas sales from the year ended December 31, 2011 to the year ended 31, 2012. December 31, 2012. Consolidated Sale of crude oil Sale of gas Total The increase in 2012 net revenue is explained by: For the year ended December 31, • an increase of US$142.2 million in oil deliveries (including US$99.5 million 2012 2011 in oil deliveries from Colombia); (in thousands of US$) • an increase of US$6.0 million from the realized price for oil sold; and 221,564 28,914 73,508 38,072 • an increase of US$1.1 million from the realized price of gas sold, partially offset by a decrease of US$10.2 million in gas deliveries. 250,478 111,580 Net revenue attributable to our operations in Chile for the year ended December 31, 2012 was US$149.9 million, a 36% increase from US$110.1 million for the year ended December 31, 2011, principally due to (1) increased Year ended sales of crude oil of 1,415 mbbl for the year ended December 31, 2012 December 31, Change from prior year compared to 864 mbbl for the year ended December 31, 2011 (an increase % 2012 (in thousands of US$, except for percentages) 2011 of 63.8%) following the discovery of the Konawentru x1 well, which was put into production in June 2012, and also other discoveries made in the Tobifera By country Chile Colombia Other Total 149,927 110,103 99,501 1,050 — 1,477 39,824 99,501 (427) 250,478 111,580 138,898 formation, and (2) an increased average realized prices per barrel of crude oil 36% from US$83.8 per barrel for the year December 31, 2011 to US$85.4 per — barrel for the year ended December 31, 2012 (an increase of US$1.6 per barrel (29)% 124% or a total of 1.9%). The increase in the average realized price per barrel was partly attributable to US$1.0 per barrel less in quality discounts in the year ended December 31, 2012 as compared to the same period in 2011. The Net revenue increased 124%, from US$111.6 million for the year ended increased sales of crude oil were partially offset by a US$9.2 million reduction December 31, 2011 to US$250.5 million for the year ended December 31, in gas sales. The contribution to our net revenue during such years from our 2012, primarily as a result of the acquisition of Luna and Winchester in operations in Chile was 60% and 99%, respectively. February 2012 and Cuerva in March 2012 in Colombia, which increased our volumes of crude sales by 41.5%, and increases in sales of crude oil in Chile. Net revenue attributable to our operations in Colombia for the year Sales of crude oil increased to 2,448 mbbl in the year ended December 31, ended December 31, 2012 was US$99.5 million. Our Colombian operations 2012 compared to 864 mbbl in the year ended December 31, 2011, and contributed 39.7% to our net revenue, resulting from sales of crude oil. GeoPark 20F 139 Production costs The following table summarizes our production costs for the years ended In our Chilean operations, production costs increased by 23.6%, due to the change in revenue mix from gas to oil, which has higher production costs December 31, 2012 and 2011. than gas, and due to an increase in our oil production. In the year ended December 31, 2012, in Chile, operating expenditures per boe increased to For the year ended % Change US$10.3 per boe from US$8.3 per boe in 2011. In the year ended December December 31, from prior 31, 2012, the revenue mix for Chile was 80.7% oil and 19.3% gas, whereas 2012 2011 year for the same period in 2011 it was 65.4% oil and 34.6% gas. (in thousands of US$, except for percentages) Consolidated (including Chile, Colombia and Argentina) Depreciation Royalties Staff costs Transportation costs Well and facilities maintenance Consumables Equipment rental Other costs Total (52,307) (11,424) (14,171) (7,211) (9,385) (9,884) (5,936) (25,844) (4,843) (6,015) (2,541) (5,080) (1,687) — (18,917) (8,503) (129,235) (54,513) 85% Gross profit 486% — 122% 137% In our Colombian operations, 34.8% of our production costs were related to depreciation charges, 6.9% to royalties, 11.7% to consumables and 9.9% to equipment rental for the year ended December 31, 2012. In the year ended December 31, 2012, in Colombia, operating expenditures were US$30.4 per boe. 102% 136% 136% 184% Year ended December 31, Change from prior year 2012 2011 % (in thousands of US$, except for percentages) 84,133 39,304 (2,194) 56,888 — 179 121,243 57,067 27,245 39,304 (2,373) 64,176 48% — (1,325)% 112% Year ended December 31, Colombia Chile 2012 2011 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 (28,120) (20,964) (24,958) (7,088) (8,560) (5,986) (6,290) (2,717) — (4,164) (7,432) (1,045) (2,850) (7,090) (5,936) (4,634) (6,802) (2,427) (4,817) (1,626) — (7,033) (10,716) (7,951) (65,794) (60,197) (53,215) Gross profit increased 112%, from US$57.1 million for the year ended December 31, 2011 to US$121.2 million for the year ended December 31, 2012, as a result of our Colombian acquisitions and increased revenues in our Chilean operations. As a result, gross margin for the year ended December 31, 2012 was 48%, which represented a decrease of 3% as compared to the gross margin for the year ended December 31, 2011. Gross profit per boe increased 49%, from US$20.6 for the year ended December 31, 2011 to US$30.7 for the year ended December 31, 2012. — — — — — — — — — Production costs increased 137%, from US$54.5 million for the year ended Gross profit attributable to our operations in Chile for the year ended December 31, 2011 to US$129.2 million for the year ended December 31, December 31, 2012 was US$84.1 million, a 48% increase from US$56.9 million 2012, primarily due to the addition of US$60.2 million in such costs from our for the year ended December 31, 2011. The contribution to our gross profit Colombian operations. during such years from our operations in Chile was 69% and 100%, respectively. Gross profit attributable to our operations in Colombia for the year ended December 31, 2012 was US$39.3 million. The contribution to our gross profit during such period was 32%. 140 GeoPark 20F Exploration costs Year ended compared to US$1.9 million during 2011, and (3) the incorporation of our December 31, Change from prior year Colombian operations into our results. amounting to US$2.9 million during 2012, as compared to US$1.7 million during 2011, (2) consultant fees amounting to US$5.1 million during 2012, as 2012 2011 % (in thousands of US$, except for percentages) Selling expenses Chile Colombia Other Total (20,452) (7,486) (5,528) (1,910) — (2,580) (12,966) (5,528) 670 (27,890) (10,066) 17,824 173% — (26)% 177% Year ended December 31, Change from prior year 2012 2011 % (in thousands of US$, except for percentages) Exploration costs increased 177%, from US$10.1 million for the year ended Chile December 31, 2011 to US$27.9 million for the year ended December 31, Colombia 2012, primarily as the result of a 173% increase in exploration costs in Chile, Other (5,327) (18,953) (351) (2,231) — (315) (3,096) (18,953) (36) which represented 73% of our exploration costs in 2012. In 2012, we recorded Total (24,631) (2,546) (22,085) 139% — 11% 867% write-offs relating to five of our Chilean wells (two in the Fell Block, two in the Otway Block and one in the Tranquilo Block) and three of our Colombian Selling expenses increased 867%, from US$2.6 million for the year ended wells (one in the Cuerva Block, one in the Arrendajo Block and one in the December 31, 2012 to US$24.6 million for the year ended December 31, 2011, Llanos 17 Block) for a total of US$23.6 million, as compared to write-offs in primarily due to higher transportation costs in 2012 in connection with our respect of three of our Chilean wells for a total of US$5.9 million in 2011; Colombian operations, in an amount of US$18.9 million. In our Chilean and a loss of US$1.9 million generated by our voluntary relinquishment of operations, selling expenses were US$3.1 million, or 139%, higher compared exploration acreage in the Del Mosquito Block in Argentina in 2012, recorded to the prior year, primarily as a result of (1) a DOP penalty payment in the in our Other operations, compared to a write-off in respect of charges from amount of US$1.7 million to Methanex as a result of our failure to meet our assets relating to the Del Mosquito Block in the amount of US$1.3 million minimum volume delivery requirements under the Methanex Gas Supply in 2011. See Note 11 to our Annual Consolidated Financial Statements. Agreement for each of the months of April through September of 2012 and The incorporation of our Colombian operations into our results resulted in (2) an increase of US$1.4 million that was primarily due to higher oil sales a US$5.5 million (including US$5.1 million in write-offs described above) volumes in Chile. increase in our exploration costs for 2012. Operating profit (loss) Administrative costs Year ended December 31, 2012 2011 Change from prior year % (in thousands of US$, except for percentages) Chile (10,879) (7,393) (10,526) (6,396) — (11,773) (4,483) (7,393) 1,247 (28,798) (18,169) (10,629) 70% Colombia Other Total — 11% 59% Chile Colombia Other Total Year ended December 31, 2011 2012 Change from prior year % (in thousands of US$, except for percentages) 47,915 8,499 (15,667) 40,747 39,425 — (13,641) 25,784 8,490 8,499 (2,026) 14,963 22% — 15% 58% Administrative costs increased 59%, from US$18.2 million for the year ended Colombian operations into our results and a 22% increase in our Chilean December 31, 2011 to US$28.8 million for the year ended December 31, operations in the year ended December 31, 2012 as compared to the prior 2012, as a result of (1) an increase in costs in our Chilean and other operations year, which was partially offset by the operating loss in Other. Operating profit increased 58.0%, primarily due to the incorporation of our due to higher costs relating to analyzing new business developments and expansion, including our Colombian acquisitions and our Brazil Acquisitions, GeoPark 20F 141 Financial results, net Financial loss increased 21% to US$16.3 million, primarily due to the December 31, 2011 and 2012 was 59% and 44%, respectively, due in part to a non-recurring tax exempted bargain purchase gain on acquisition incurrence of a US$37.5 million loan to partly finance our Colombian of subsidiaries. acquisitions, and an increase in exchange difference of US$0.5 million in the year ended December 31, 2011 as compared to US$2.5 million in the year Profit for the year ended December 31, 2012, mainly due to the strengthening of the Chilean peso against the U.S. dollar, from Ch$519.2 as of December 31, 2011 to Ch$478.6 as of December 31, 2012, which negatively affected our liability net position in local currency related to tax payables. Year ended Chile December 31, Change from prior year Colombia 2012 2011 % (in thousands of US$, except for percentages) Other Total Year ended December 31, Change from prior year 2012 2011 % (in thousands of US$, except for percentages) 30,923 6,247 (18,724) 18,446 19,455 — (14,393) 5,062 11,468 6,247 (4,331) 13,384 59% — 30% 264% Chile Colombia Other Total 42,272 11,223 (20,655) 32,840 26,649 — (14,381) 12,268 15,623 11,223 (6,274) 20,572 59% — For the year ended December 31, 2012, we recorded a profit of US$18.4 44% million, a 264% increase from US$5.1 million for the year ended December 31, 168% 2011, as a result of the reasons described above. For the year ended December 31, 2012, we recorded a profit before income Profit for the year attributable to owners of the Company tax of US$32.8 million, an increase of 168% from US$12.3 million for the year ended December 31, 2011, primarily due to the incorporation of our Profit for the year attributable to owners of the Company increased for the Colombian operations into our results and a bargain purchase gain on reasons described above. Profit attributable to non-controlling interest acquisition of subsidiaries of US$8.4 million as a result of the acquisitions increased by 31% to US$6.6 million in the year ended December 31, 2012 as of Winchester and Luna in the year ended December 31, 2012. compared to the prior year due to increased profit in our Chilean operations. Income tax B. Liquidity and capital resources Year ended December 31, Change from prior year Overview Our financial condition and liquidity is and will continue to be influenced by 2012 2011 % a variety of factors, including: Chile Colombia Other Total (in thousands of US$, except for percentages) 58% (4,155) (7,194) (11,349) • our ability to generate cash flows from our operations; (4,976) 1,931 — (12) (14,394) (7,206) (4,976) 1,943 (7,188) — • our capital expenditure requirements; 16,192% • the level of our outstanding indebtedness and the interest we are obligated 100% to pay on this indebtedness; and • changes in exchange rates which will impact our generation of cash flows Income tax increased 100%, from US$7.2 million for the year ended from operations when measured in U.S. dollars, and, upon the completion December 31, 2011 to US$14.4 million for the year ended December 31, 2012, of our Brazil Acquisitions, the real. as a result of the incorporation of our Colombian operations into our results and a 58% increase in income tax in our Chilean operations, consistent with Our principal sources of liquidity have historically been contributed the improved profitability of our Chilean operations, offset by the recognition shareholder equity, debt financings and cash generated by our operations in of a deferred tax asset of US$1.9 million resulting from expenses generated the Fell Block, and, since our acquisitions of Winchester and Luna in the first at our Chilean holding company. Our effective tax rate for the years ended quarter of 2012, cash generated by our operations in our blocks in Colombia. 142 GeoPark 20F We have a proven ability to raise capital. Since 2005 to 2013, we have raised Colombia and other investments of US$198.2 million, including the more than US$109.5 million in equity offerings at the holding company level drilling of 45 new wells and seismic surveys registered, principally in our and more than US$557 million through debt arrangements with multilateral Tierra del Fuego Blocks. In the year ended December 31, 2011, our agencies such as the IFC, gas prepayment facilities with Methanex, total capital expenditures amounted to US$98.7 million, all of which was international bond issuances and bank financings, described further below, used in exploration, development and production activities, including which have been used to fund our capital expenditures program and US$57.9 million for the drilling of development wells and facilities and acquisitions and to increase our liquidity. US$39.5 million for the drilling of exploratory wells and seismic studies. We have also raised US$173.3 million to date through our strategic In the year ended December 31, 2013, we made total capital expenditures partnership with LGI following the sale of minority interests in our Colombian of US$228.0 million (US$145.7 million, US$82.1 million and US$0.2 million and Chilean operations. in Chile, Colombia and Argentina, respectively), consisting of US$133.3 million related to exploration. 39 new wells were drilled (17 in Chile and 22 in We initially funded our 2012 expansion into Colombia through a US$37.5 Colombia) in blocks in which we have working interests and/or economic million loan, cash on hand and a subsequent sale of a minority interest in interests. In addition to the above, in 2013 we completed approximately 1,350 our Colombian operations to LGI. We subsequently restructured our sq. km. in 3D seismic surveys (more than 1,100 sq. km in Chile, mainly related outstanding debt in February 2013, by issuing US$300.0 million aggregate to the blocks located in Tierra del Fuego and over 250 sq. km in Colombia). 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 outstanding In March 2014 we invested US$140 million in Brazil, subject to certain Notes due 2015. See “Item 4. Information on the Company—Business adjustments, to acquire Rio das Contas, which we financed through the Overview—Significant Agreements—Argentina—Agreements with LGI.” incurrence of a loan of US$70.5 million and cash on hand. In February 2014, we commenced trading on the NYSE and raised US$98 In 2014, we expect our total capital expenditures, excluding the purchase million (before underwriting commissions and expenses), including the over price for our Rio das Contas acquisition, to be between US$220 million to allotment option granted to and exercised by the underwriters, through US$250 million. These capital expenditures will include the drilling of a total the issuance of 13,999,700 common shares. of 50 to 60 new wells (approximately 40% of which we expect will be exploratory wells), as well as workovers, seismic surveys and new facility In March 2014, we borrowed US$70.5 million pursuant to a five-year term construction. We expect that approximately 62% of our total capital variable interest secured loan, secured by the benefits GeoPark receives under expenditures for 2014 will be incurred in Chile, which will include the the Purchase and Sale Agreement for Natural Gas with Petrobras, equal to drilling of approximately 32 to 37 wells, as well as workovers, seismic surveys six-month LIBOR + 3.9% to finance part of the purchase price of our Rio das and new facility construction, including oil pipelines. We expect that Contas acquisition, and funded the remaining amount with cash on hand. approximately 32% of our total capital expenditures for 2014 will be incurred We believe that our cash and cash equivalents on hand, and cash from operations will be adequate to meet our capital expenditure requirements, in Colombia, which will include the drilling of approximately 18 to 23 wells, as well as workovers and new facility construction, mainly related to civil and liquidity needs for the foreseeable future. works, production facilities in the Tua and Tigana fields and improvements to the Taro Taro and Max fields facilities. Finally, we expect that Capital expenditures We have funded our capital expenditures with proceeds from equity approximately 5% of our total capital expenditures for 2014 will be incurred in Brazil, which will consist of between US$5 million to US$7.5 million to offerings, credit facilities, debt issuances and pre-sale agreements, as well as finance in part the construction of a gas compression plant in the Manatí through cash generated from our operations. We expect to incur substantial Field we acquired as part of our Rio das Contas acquisition and approximately expenses and capital expenditures as we develop our oil and natural gas US$0.45 million in license fee payments to the ANP relating to our Round prospects and acquire additional assets. 12 concessions, with the remainder for seismic surveys in exploration blocks in the Potiguar and Recôncavo Basins. In the year ended December 31, 2012, we made total capital expenditures of US$303.5 million, which consisted of investments of US$105.3 million relating to the purchase price for our acquisitions of Winchester, Luna and Cuerva in GeoPark 20F 143 In budgeting for our future activities, we have relied on a number of assumptions, including, with regard to our discovery success rate, the number Cash flows provided by operating activities For the year ended December 31, 2013, cash provided by operating of wells we plan to drill, our working interests in our prospects, the costs activities was US$140.1 million, a 6.3% increase from US$131.8 million for the involved in developing or participating in the development of a prospect, the year ended December 31, 2012. This increase is mainly driven by higher timing of third-party projects and our ability to obtain needed financing in production and revenues that we obtained during 2013, partially offset by respect to any further acquisitions and the availability of both suitable higher associated costs. equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and For the year ended December 31, 2012, cash provided by operating activities competitive uncertainties, conditions in the financial markets, contingencies was US$131.8 million, a 92% increase from US$68.8 million for the year and risks, all of which are difficult to predict and many of which are beyond ended December 31, 2011. This increase was principally due to increased cash our control. In addition, we opportunistically seek out new assets and generated in our operations and the incorporation of US$20.8 million in acquisition targets to complement our existing operations, and have operating cash flows from our Colombian operations into our results. financed such acquisitions in the past through the incurrence of additional indebtedness, including additional bank credit facilities, equity issuances or the sale of minority stakes in certain operations to our partners. We may Cash flows used in investing activities For the year ended December 31, 2013, cash used in investing activities was need to raise additional funds more quickly if one or more of our assumptions US$221.3 million, a 27.1% decrease from US$303.5 million for the year ended prove to be incorrect or if we choose to expand our hydrocarbon asset December 31, 2012. This decrease was primarily related to our Colombian acquisition, exploration, appraisal or development efforts more rapidly than acquisitions, which occurred in the first quarter of 2012. This amount was we presently anticipate, and we may decide to raise additional funds even only partially offset by an increase of US$29.8 million in capital expenditures before we need them if the conditions for raising capital are favorable. relating to the drilling of 39 new wells (17 in Chile and 22 in Colombia) and The ultimate amount of capital that we will expend may fluctuate materially seismic surveys and facilities construction, as compared to the drilling of 35 based on market conditions, our continued production, decisions by the wells (15 in Chile and 20 in Colombia) for the year ended December 31, 2012. operators in blocks where we are not the operator, the success of our drilling results and future acquisitions. Our future financial condition and liquidity Cash used in investing activities increased by US$202.2 million during the will be impacted by, among other factors, our level of production of oil and year ended December 31, 2012, from US$101.3 million in 2011 to natural gas and the prices we receive from the sale thereof, the success US$303.5 million in 2012. This increase includes US$105.3 million related to of our exploration and appraisal drilling program, the number of the purchase price for our Colombian operations (net of cash acquired); commercially viable oil and natural gas discoveries made and the quantities the remaining increase is primarily explained by increased drilling activities of oil and natural gas discovered, the speed with which we can bring such in 2012 (20 wells in Chile and 24 in Colombia) as compared to 23 new discoveries to production and the actual cost of exploration, appraisal and wells in 2011. development of our oil and natural gas assets. Cash flows The following table sets forth our cash flows for the periods indicated: Cash flows provided by financing activities Cash provided by financing activities was US$164.0 million for the year ended December 31, 2013, compared to cash provided by financing activities of US$26.4 million for the year ended December 31, 2012. This change was Cash flows provided by (used in) Operating activities Investing activities Financing activities Year ended December 31, principally the result of cash received in the 2013 period from the issuance 2013 2012 2011 of US$300.0 million of our Notes due 2020 and an increase of US$36.6 million (in thousands of US$) in cash from LGI pertaining principally to its investment in our Colombian and Chilean operations. These were partially offset by the early redemption 140,094 131,802 68,763 of our Notes due 2015 and the repayment of the Banco Itaú BBA Credit (221,299) (303,507) (101,276) Agreement, in an aggregate amount of US$175.0 million. 164,018 26,375 131,739 Net increase (decrease) in cash Cash provided by financing activities was US$26.4 million and US$131.7 and cash equivalents 82,813 (145,330) 99,226 million during the years ended December 31, 2012 and 2011, respectively. This decrease was principally the result of a US$129.5 million reduction in 144 GeoPark 20F proceeds from transactions relating to non-controlling interest, resulting Notes due 2020 from LGI’s acquisition of a 20% interest for US$148 million, of which US$142 million was collected in 2012, in our Chilean operations in the year ended December 31, 2011. In the year ended December 31, 2012, LGI contributed General On February 11, 2013, we issued US$300.0 million aggregate principal US$12.5 million in cash provided by financing activities pursuant to its direct amount of senior secured notes due 2020. The Notes due 2020 mature on investment in our Chilean operations. The US$129.5 million decrease February 11, 2020 and bear interest at a fixed rate of 7.50% and a yield of was only partly offset by cash provided through the incurrence of a US$37.5 7.625% per annum. Interest on the Notes due 2020 is payable semi-annually million loan to partly finance our Colombian acquisitions. in arrears on February 11 and August 11 of each year. Indebtedness As of December 31, 2013 and 2012, we had total outstanding indebtedness Ranking The Notes due 2020 constitute senior obligations of Agencia, secured by a of US$317.1 million and US$193.0 million, respectively, as set forth in the first lien on certain collateral (as described below). The Notes due 2020 rank table below. Methanex Gas Prepayment Agreement BCI Loans(1) Bond GeoPark Fell SpA (Notes due 2015)(2) Bond GeoPark Latin America Agencia en Chile (Notes due 2020) Banco Itaú BBA Credit Agreement Banco de Chile(4) Overdrafts(5) Total(3) equally in right of payment with all senior existing and future obligations of Agencia (except those obligations preferred by operation of Bermuda and As of December 31, Chilean law, including, without limitation, labor and tax claims); effectively 2013 2012 senior to all unsecured debt of Agencia and GeoPark Latin America, to the (in thousands of US$) extent of the value of the collateral; senior in right of payment to all existing — 2,143 8,036 7,859 and future subordinated indebtedness of Agencia and GeoPark Latin America; and effectively junior to any future secured obligations of Agencia and its — 129,452 subsidiaries (other than additional notes issued pursuant to the indenture governing the Notes due 2020) to the extent secured by assets constituting 299,912 — with a security interest on assets not constituting collateral, in each case to — 37,685 the extent of the value of the collateral securing such obligations. 15,002 — 30 10,000 317,087 193,032 Guarantees The Notes due 2020 are guaranteed unconditionally on an unsecured basis by us, all of our wholly-owned subsidiaries, and any subsidiary that guarantees (1) Includes BCI Mortgages and BCI Letters of Credit (each as defined herein). any of our debt, subject to certain exceptions. (2) On December 2, 2010, we issued US$133.0 million aggregate principal amount of Notes due 2015. The notes were fully redeemed with the proceeds from the issuance of our Notes due 2020. Collateral The notes are secured by a first-priority perfected security interest in certain (3) Does not include US$8.5 million outstanding as of December 31, 2013 under a subordinated line of credit extended by LGI to GeoPark Colombia collateral, which consists of: 80% of the equity interests of each of GeoPark Chile and GeoPark Colombia held by Agencia, and loans of the net proceeds S.A.S. in December 2012. See Note 28 of our Consolidated Financial of the Notes due 2020 made by Agencia to each of GeoPark Fell and GeoPark Statements. Llanos SAS. Except for certain immaterial subsidiaries and other exceptions, (4) Short-term financing obtained in December 2013 and fully repaid in GeoPark and Agencia are also required to pledge the equity interests of our January 2014. subsidiaries. (5) We have been granted credit lines for over US$76 million as of December 31, 2013. The Notes due 2020 are also secured on a first-priority basis by intercompany loans, disbursed to subsidiaries, in an aggregate amount at any one time that On March 28, 2014, we incurred US$70.5 million pursuant to the Rio das does not exceed US$300.0 million. Contas Credit Facility to finance the Rio das Contas acquisition. Our material outstanding indebtedness as of December 31, 2013 is described below. 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% GeoPark 20F 145 of the principal amount of such Notes due 2020 plus an applicable “make- grade ratings from at least two of the following rating agencies, Standard whole” premium, plus accrued and unpaid interest (including, additional & Poor’s Rating Group, Fitch Inc. and Moody’s Investors Service, Inc., and no amounts), if any, as such term is defined in the indenture governing the Notes default has occurred or is continuing under the indenture governing due 2020, if any, to the redemption date. the Notes due 2020, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, At any time and from time to time on or after February 11, 2017, we may, restricted payments (including restrictions on our ability to pay dividends), at our option, redeem all or part of the Notes due 2020, at the redemption the ability of certain subsidiaries to pay dividends, asset sales and certain prices, expressed as percentages of principal amount, set forth below, plus transactions with affiliates will no longer be applicable. accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on February 11 of the years indicated below: Events of default Events of default under the indenture governing the Notes due 2020 include: the nonpayment of principal when due; default in the payment of interest, Year 2017 2018 2019 and after Percentage which continues for a period of 30 days; failure to make an offer to purchase 103.750% and thereafter accept tendered notes following the occurrence of a change 101.875% of control or as required by certain covenants in the indenture governing 100.000% the Notes due 2020; default in the performance or breach of the covenants contained in the indenture, the notes, or the security documents in relation In addition, at any time prior to February 11, 2016, we may, at our option, thereto that continues for a period of 60 consecutive days after written notice redeem up to 35% of the aggregate principal amount of the Notes due to Agencia; cross payment default relating to debt with a principal amount 2020 (including any additional notes) at a redemption price of 107.50% of of US$15.0 million or more, and cross-acceleration default following a the principal amount thereof, plus accrued and unpaid interest (including judgment for US$15.0 million or more; bankruptcy and insolvency events; additional amounts) if any to the redemption date, with the net cash invalidity or denial or disaffirmation of a guarantee of the notes; and failure proceeds of one or more equity offerings; provided that: (1) Notes due 2020 to maintain a perfected security interest in any collateral having a fair market in an aggregate principal amount equal to at least 65% of the aggregate value in excess of US$15.0 million, among others. The occurrence of an principal amount of Notes due 2020 issued on the first issue date remain event of default would permit or require the principal of and accrued interest outstanding immediately after the occurrence of such redemption; and on the Notes due 2020 to become or to be declared due and payable. (2) the redemption must occur within 90 days of the date of the closing of such equity offering. BCI Mortgage Loan In October 2007, in connection with our acquisition of a facility to establish Change of control Upon the occurrence of certain events constituting a change of control, we an operational base in the Fell Block, we executed a mortgage loan granted by the Banco de Crédito e Inversiones, or BCI, a Chilean private bank, which 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 we refer to as the BCI Mortgage Loan. The loan was granted in Chilean pesos and is repayable over a period of eight years. The interest rate under this any accrued and unpaid interest (including any additional amounts payable loan is fixed at 6.6%. As of December 31, 2013, the aggregate outstanding in respect thereof) thereon to the date of purchase. amount under the BCI Mortgage Loan was US$0.2 million. Covenants The Notes due 2020 contain customary covenants, which include, among BCI Letter of Credit During the last quarter of 2011, we obtained five short-term letters of credit others, limitations on: the incurrence of debt and disqualified or preferred from BCI, or, collectively, the BCI Letters of Credit, to commence operations stock, restricted payments (including restrictions on our ability to pay in our Tierra del Fuego blocks. Each of the BCI Letters of Credit contains a dividends), incurrence of liens, transfer, prepayment or modification pledge by us to BCI of the seismic equipment acquired to start the operations of certain collateral, guarantees of additional indebtedness, the ability of in these new blocks. The BCI Letters of Credit expired and were fully paid by certain subsidiaries to pay dividends, asset sales, transactions with affiliates, us on February 14, 2014, and the applicable interest rate ranges from 4.5% engaging in certain businesses, and merger or consolidation with or to 5.45%. As of December 31, 2013, the aggregate outstanding amount under into another company. In the event the Notes due 2020 receive investment- the BCI Letters of Credit was US$1.9 million. 146 GeoPark 20F LGI Line of Credit In December 2012, in connection with its investment in GeoPark Colombia, F. Tabular disclosure of contractual obligations In accordance with the terms of our concessions, we are required to make LGI granted as a credit line to Winchester (now GeoPark Colombia S.A.S.), royalty payments (1) in connection with crude oil and gas production in or the LGI Line of Credit, of up to US$12.0 million, to be used for the Argentina, to the Provinces of Santa Cruz and Mendoza, equivalent to 12% acquisition, development and operation of oil and gas assets in Colombia. on estimated value at well head, (2) in connection with crude oil and gas In December 2015, the principal amount of any outstanding amounts shall production in Chile, to the Chilean government, equivalent to approximately become immediately due and payable. GeoPark Colombia S.A.S. may also, 5% of crude oil production and 3% of gas production, and (3) in connection in its sole discretion, choose to make repayments of the principal amounts with crude oil production in Colombia, to the Colombian government, outstanding on the last business day of March, June, September and equivalent to 8%. December of each year until December 2015. The applicable interest rate is 8.00% per annum and any accrued interest is payable on a quarterly basis. Less than One to Three to More than As of December 31, 2013, the aggregate outstanding amount under the LGI Total one year three years five years five years Line of Credit was US$8.5 million. See “Item 4. Information on the Company— B. Business Overview—Significant Agreements—Agreements with LGI.” Rio das Contas Credit Facility We financed our Rio das Contas acquisition in part through our Brazilian subsidiary’s entrance into a US$70.5 million credit facility (the “Rio das Contas Credit Facility”) with Itau BBA International plc, which is secured by the Debt obligations(1) Operating lease obligations(2) Pending (in thousands of US$) 317,087 26,630 98 — 290,359 157,023 68,817 56,556 31,145 505 benefits GeoPark receives under the Purchase and Sale Agreement for Natural Gas with Petrobras. The facility matures five years from March 28, 2014, which was the date of disbursement and bears interest at a variable interest investment commitments(3) 87,488 Asset rate equal to the six-month LIBOR + 3.9%. The facility agreement includes retirement 44,428 43,060 — — customary events of default, and subject our Brazilian subsidiary to customary obligations 24,166 — 11,644 448 12,074 covenants, including the requirement that it maintain a ratio of net debt to Total EBITDA of up to 3.5x the first two years and up to 3.0x thereafter. The credit contractual facility also limits the borrower’s ability to pay dividends if the ratio of net obligations 585,764 139,875 111,358 31,593 302,938 debt to EBITDA is greater than 2.5x. We have the option to prepay the facility in whole or in part, at any time, subject to a pre-payment fee to be (1) Includes current borrowings and non-current borrowings. determined under the contract. (2) Reflects the future aggregate minimum lease payments under non- cancellable operating lease agreements. C. Research and development, patents and licenses, etc. See “Item 4. Information on the Company—B. Business Overview” and “Item (3) Includes capital commitments in Isla Norte, Campanario and Flamenco Blocks in Chile, nine concessions in Brazil and the Llanos 62 and Llanos 17 4. Information on the Company—B. Business Overview—Title to Properties.” Blocks in Colombia, which are our only remaining material commitments. See D. Trend information For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations.” “Item 4. Information on the Company—B. Business overview—Our operations—Operations in Colombia.” On March 28, 2014, we incurred US$70.5 million pursuant to the Rio das Contas Credit Facility to finance the Rio das Contas acquisition. E. Off-balance sheet arrangements We did not have any off-balance sheet arrangements as of December 31, 2012 or as of December 31, 2013. G. Safe harbor See “Forward-Looking Statements.” GeoPark 20F 147 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 2014. The current members of the board of directors were appointed at a shareholders’ meeting held on July 30, 2013. The table below sets forth certain information concerning our current board of directors. Name Gerald E. O’Shaughnessy James F. Park Carlos Gulisano Juan Cristóbal Pavez(1)(2) Peter Ryalls(1)(2) Steven J. Quamme(1) Pedro Aylwin Director Position Chairman and Director Chief Executive Officer, Deputy Chairman and Director Director Director Director Director Director of Legal and Governance Age At the Company since 65 58 63 44 63 53 54 2002 2002 (3)2010 2008 2006 2011 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 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. 148 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 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 his graduation from the University of Notre Dame with degrees in degree in petroleum engineering and a PhD in geology from the University government (1970) and law (1973), Mr. O’Shaughnessy was engaged in the of Buenos Aires and has authored or co-authored over 40 technical papers. practice of law in Minnesota. Mr. O’Shaughnessy has been active in the oil He is a former adjunct professor at the Universidad del Sur, a former thesis and gas business over his 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 works and management experience in the oil and gas industry. In addition to for Lukoil in Russia during the 1990s. In 2010 Mr. O’Shaughnessy founded serving as an advisor to GeoPark since 2002 and as Managing Director from Lario Logistics, a U.S. midstream company which owns and operates the February 2008 until June 2010, Dr. Gulisano has worked for YPF, Petrolera Bakken Oil Express, serving oil producers and service providers in the Bakken Argentina San Jorge S.A. and Chevron San Jorge S.A. and has led teams Oil play. In addition to his oil and gas activities Mr. O’Shaughnessy is also credited with significant oil and gas discoveries, including those in the Trapial engaged in investments in banking, wealth management, desktop software, field in Argentina. He has worked in Argentina, Bolivia, Peru, Ecuador, computer and network security, and green clean technology. Over the Colombia, Venezuela, Brazil, Chile and the United States. Mr. Gulisano is also past 25 years, Mr. O’Shaughnessy has also served on a number of non-profit an independent consultant on oil and gas exploration and production. 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 Juan Cristóbal Pavez has been a member of our board of directors since August 2008. He holds a degree in commercial engineering from the and The Bill of Rights Institute. Mr. O’Shaughnessy is a member of the Pontifical Catholic University of Chile and a MBA from the Massachusetts Intercontinental Chapter of Young Presidents Organization and World Institute of Technology. He has worked as a research analyst at Grupo CB Presidents’ Organization. and later as a portfolio analyst at Moneda Asset Management. In 1998, he joined Santana, an investment company, as Chief Executive Officer. At 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 extensive experience in all phases of the upstream oil and gas business, with Andrómaco, one of Santana’s main assets. In 1999, Mr. Pavez cofounded a strong background in the acquisition, implementation and management Eventures, an internet company. Since 2001, he has served as Chief of international joint ventures in North America, South America, Asia, Europe Executive Officer at Centinela, a company with a diversified global portfolio and the Middle East. He holds a degree in geophysics from the University of investments, with a special focus in the energy industry, through the of California at Berkeley and has worked as a research scientist in earthquake development of wind parks and run-of-the-river hydropower plants. and tectonic studies. In 1978, Mr. Park joined Basic Resources International Limited, an oil and gas exploration company, which pioneered the 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 development of commercial oil and gas production in Central America. of several companies, including Quintec, Enaex, CTI and Frimetal. 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 149 Peter 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 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 London. Mr. Ryalls has worked for Schlumberger Limited in Angola, Gabon 2003 to 2006, Mr. Aylwin worked for us as an advisor on governance and and Nigeria, as well as for Mobil North Sea. He has also worked for Unocal legal matters. Mr. Aylwin holds a degree in law from the Universidad de Chile Corporation where he held increasingly senior positions, including as and an LLM from the University of Notre Dame. Mr. Aylwin has extensive Managing Director in Aberdeen, Scotland, and where he developed extensive experience in the natural resources sector. Mr. Aylwin is also a partner at the experience in offshore production and drilling operations. In 1994, Mr. Ryalls law firm of Aylwin Abogados in Santiago, Chile, where he represented mining, represented Unocal Corporation in the Azerbaijan International Operating chemical and oil and gas companies in numerous transactions. From 2006 Company as Vice President of Operations and was responsible for production, until 2011, he served as Lead Manager and General Counsel at BHP Billiton, drilling, reservoir engineering and logistics. In 1998, Mr. Ryalls became Base Metals, where he was in charge of legal and corporate governance General Manager for Unocal in Argentina. He also served as Vice President matters on BHP Billiton’s projects, operations and natural resource assets in of Unocal’s Gulf of Mexico onshore oil and gas business and as Vice President South America, North America, Asia, Africa and Australia. Mr. Aylwin is of Global Engineering and Construction, where he was responsible for also a member of the board of directors of Egeda España. 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. Steven J. Quamme has been a member of our board of directors since June 2011. He has 25 years of experience as a fund manager, securities and corporate lawyer, and investment banker. Mr. Quamme holds a B.A. in economics from Northwestern University and a J.D. from the Northwestern University School of Law, where he is a member of the Law School Board. Mr. Quamme is a member of the board of directors of Cartica Management, LLC, as well as the board of trustees of The Potomac School and of the Sibley Memorial Hospital Foundation. He has previously served as a member of the boards of directors of Equivest Finance, Milestone Merchant Partners, LLC, Kerrco Inc., Atlantic Entertainment Group, Rausch Industries, Rompetrol, and Einstein Noah Bagel Corp, LP. From 2005 to 2007, Mr. Quamme served as the Chief Operating Officer of Breeden Partners, a corporate governance fund. From 2002 to 2007, Mr. Quamme also served as Senior Managing Director of Richard C. Breeden & Co., a professional services firm, which focuses on corporate governance and crisis management. In 2000, Mr. Quamme founded Milestone Merchant Partners, a merchant bank based in Washington D.C., where he served as its CEO until 2005. Mr. Quamme is presently a co-founder and Senior Managing Director of Cartica Management, a registered investment advisor focused on emerging markets and a GeoPark shareholder. 150 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 Augusto Zubillaga Pedro Aylwin Chiorrini Gerardo Hinterwimmer Salvador Harambour Marcela Vaca Dimas Coelho Carlos Murut Salvador Minniti Jose Díaz Horacio Fontana Ruben Marconi Agustina Wisky Guillermo Portnoi Pablo Ducci Position Chief Executive Officer and Director Chief Financial Officer Managing Director of Operations Director of Legal and Governance Director for Argentina Director for Chile Director for Colombia Director for Brazil Director of Development Geology Director of Exploration Director of Operations 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 58 36 44 54 57 53 45 57 57 59 59 56 69 37 39 34 2002 2010 2006 2003 2003 2009 2012 2013 2006 2007 2013 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 Managing Director of Operations since January 2012. He previously served as our Production Director. He is a our executive officers is Nuestra Señora de los Ángeles 179, Las Condes, petroleum engineer with 19 years of experience in production, engineering, Santiago, Chile. well completions, corrosion control, reservoir management and field development. He has a degree in petroleum engineering from the Instituto Andrés Ocampo has served as our Chief Financial Officer since November 2013. He previously served as our Director of Growth and Capital (from Tecnológico de Buenos Aires. Prior to joining our company, Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. January 2011 through October 2013), and has been with our company since July 2010. Mr. Ocampo graduated with a degree in Economics from the At Chevron San Jorge S.A., he led multi-disciplinary teams focused on improving production, costs and safety, and was the leader of the Asset Universidad Católica Argentina. He has more than 12 years of experience Development Team, which was responsible for creating the field in business and finance. Before joining our company, Mr. Ocampo worked at development plan and estimating and auditing the oil and gas reserves Citigroup and served as Vice President Oil & Gas and Soft Commodities at of the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron Crédit Agricole Corporate & Investment Bank. 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 151 Gerardo Hinterwimmer has served as our Director for Argentina since April 2012. He previously served as our Geosciences Director. He holds a degree in responsible for the planning, management and execution of the exploration programs in the exploration blocks in Brazil’s Santos Basin, and as Joint geology from Universidad Nacional de la Plata. He is a development geologist Venture Project Manager (in 2011), in which role he was responsible for the in Argentina and an expert in the Magallanes Austral Basin, with over 25 years coordination of Petrobras’s functional areas to support Petrobras’s work of experience working for international and major oil companies, including programs in the Santos Basin. In 2012, he served as Executive Vice President YPF S.A., Schlumberger Limited, Petrolera Argentina San Jorge S.A. and of Exploration at Panoro, where he oversaw the functional workflow for Chevron San Jorge S.A. Mr. Hinterwimmer has experience in studying and Panoro Energy ASA’s exploration assets in Brazil. Dr. Dimas holds a degree evaluating unconventional volcanic clastic reservoirs in the Austral Basin and in geology from the Federal University of Rio de Janeiro, Brazil, an MSc degree has been credited with commercial oil and gas discoveries in the Austral in geophysics (seismic processing) from the Federal University of Bahia, and Neuquen Basins. He is the author of numerous technical papers and is Brazil, a Ph.D. in geology (Numerical Basin Modelling) from Cornell University an editor of the reference manual on productive reservoirs in Argentina. and an MBA in general administration from the Federal University of Rio de He has also contributed to the development of recent geological-oriented Janeiro, Brazil. technology introduced by Schlumberger Limited in South America. Salvador Harambour has served as our Director for Chile since 2009. He is an oil and gas manager with more than 27 years of experience in the energy Carlos Murut has been our Director of Development Geology since January 2012. He previously served as our Development Manager. Mr. Murut holds a master’s degree in petroleum geology from the University of Buenos Aires industry. He holds a degree in geology from the Universidad de Chile and where he also undertook postgraduate studies in reservoir engineering, an MsC on basin analysis from the University of London. Prior to joining our specializing in field exploitation. Mr. Murut has over 30 years of experience company, Mr. Harambour spent 24 years at ENAP, beginning in 1985 as Field working for international and major oil companies, including YPF S.A., Geologist. In 1993, he joined Sipetrol and worked as Exploration Geologist Tecpetrol S.A., Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. on several Latin American and European ventures. In 2003, he joined ENAP Sipetrol Argentina, and in 2005, he was appointed General Manager of ENAP Sipetrol in Argentina, until he joined GeoPark in 2009. Marcela Vaca has been our Director for Colombia since August 2012. Ms. Vaca holds a degree in law from Pontificia Universidad Javeriana in Bogotá, 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 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., Colombia, a Master’s Degree in commercial law from the same university and Petrolera 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 José Díaz has been our Director of Operations since January 2013. Mr. Díaz holds a degree in petroleum engineering from Cuyo National University, 2003, she served as Legal and Administrative Manager at GHK Company Argentina, has taken executive business classes at IAE Business School, Colombia. Prior to joining our company in 2012, Ms. Vaca served for nine years as General Manager of the Hupecol Group where she was responsible and pursued graduate studies in oil and gas law and project management at University of Buenos Aires School of Law and Alta Dirección Escuela for supervising all areas of the company as well as managing relationships de Negocios, respectively. He has over 30 years of experience in upstream with Ecopetrol, ANH, the Colombian Ministry of Mines and Energy, the operations as a petroleum engineer, including more than 15 years in Colombian Ministry of Environment and other governmental agencies. managerial positions. This experience includes positions at international At the Hupecol Group, Ms. Vaca was also involved in the structuring of the and major oil companies, including OEA S.A., Chevron San Jorge S.A., Hupecol Group’s asset development and sales strategy. 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 Horacio Fontana has been our Director of Drilling since March 2012. He previously served as our Engineer Manager. He holds a degree in civil in hydrocarbons exploration. From 1981 to 2011, Dr. Coelho served for engineering from Rosario National University and is also a graduate from the Petrobras in numerous capacities, including as Petroleum Exploration Argentine Oil and Gas Institute, National University of Buenos Aires, with a Manager (from 2001 to 2004 and from 2006 to 2010), in which role he was specialty in field exploitation and a concentration in drilling. Mr. Fontana has 152 GeoPark 20F over 25 years of drilling experience including at major Argentine companies like YPF S.A. and Petrolera Argentina San Jorge- Chevron. Executive directors’ contracts It is our policy that executive directors have contracts of an indefinite term providing for a maximum of one-year’s notice in writing of termination Rubén Marconi has been our Director of Health, Safety and Environment since March 2012. He previously served as our Drilling Director. He holds at any time. a degree in mechanical engineering from Rosario University and was Gerald E. O’Shaughnessy has a service contract with our company that a YPF scholar at the University of Buenos Aires where he graduated in provides for him to act as Executive Chairman at an annual salary of oil engineering with a concentration in exploitation. Mr. Marconi has over US$250,000. James F. Park has a service contract with our company that 40 years of field logistics and safety experience with ChevronTexaco, provides for him to act as Chief Executive Officer at an annual salary of Chevron Mid Continent Business Unit and Chevron Argentina. US$500,000. The payment of a bonus to Mr. O’Shaughnessy or Mr. Park is at Agustina Wisky has worked with our Company since it was founded in November 2002, and has served as our Director of People since 2012. our discretion. Our agreements with Mr. O’Shaughnessy and Mr. Park contain covenants that restrict them, for a period of 12 months following termination of employment, from soliciting senior employees of our company Mrs. Wisky is a public accountant, and also holds a degree in human and, for a period of six months following the termination of employments, resources from the Universidad Austral—IAE. She has 13 years of experience from being involved in any competing undertaking. Pedro Aylwin, who in the oil industry. Before joining our company, Mrs. Wisky worked at AES was appointed as an executive director in July 2013, has a service contract Gener and PricewaterhouseCoopers. with our company that provides for him to act as Director of Legal and 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, 2013. Governance. 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$300,000 from Duke University. From 2004 to 2009, Mr. Ducci worked as a Corporate Finance Analyst and Corporate Finance Associate with Celfin Capital. In 2010, Non-executive directors’ contracts Our non-executive directors are paid an annual fee of GBP35,000, which is he worked as a Summer Associate for Anka Funds, and from 2011 to 2012, payable quarterly in arrears. At our option, the fee paid to our non-executive he served as Vice President of Development for Falabella Retail. B. Compensation directors can be paid through the issuance of new common shares and/or cash. In addition, the Chairmen of the Audit Committee, the Remuneration Committee and the Nomination Committee are paid an additional annual fee of GBP5,750 each. The termination of the employment relationship does Executive compensation For the year ended December 31, 2013, the aggregate compensation not entitle non-executive directors to any financial compensation. The following chart summarizes payments made to our non-executive directors accrued or paid to the members of our board of directors (including our for the year ended December 31, 2013. executive directors) for services in all capacities was approximately US$4.6 million. Gerald E. O’Shaughnessy, James F. Park and Pedro Aylwin are our executive directors. For the year ended December 31, 2013, the aggregate compensation accrued or paid to the members of our senior management (excluding our executive directors) for services in all capacities was approximately US$6.8 million. GeoPark 20F 153 Executive director Sir Michael R. Jenkins(1) Juan Cristóbal Pavez(2) Christian Weyer(3) Peter Ryalls Carlos Gulisano Steven J. Quamme Share payment Fees paid in Performance-Based Employee Long-Term Incentive Program We have established the Performance-Based Employee Long-Term Incentive Cash payment common shares Program in order to align the interests of our management, employees Non-executive Committee (in number of and key advisors with those of our shareholders. In November 2007, directors’ fees Chairman fees common shares) our shareholders voted to authorize the board of directors to use up to a GBP4,375 GBP1,437.5 1,712 Performance-Based Employee Long-Term Incentive Program. The shareholders maximum of 12% of our issued share capital for the purposes of the GBP17,500 GBP17,240 GBP17,500 GBP35,000 GBP17,500 GBP5,750 GBP1,437.5 — GBP2,875 GBP2,875 also authorized the board of directors to implement the Performance- 2,906 Based Employee Long-Term Incentive Program and to determine specific — conditions and broadly defined guidelines for the program. 2,906 — 2,906 IPO award program and Executive Stock Option Plan On admission to AIM, our executive directors, management and key employees received options to purchase common shares of the Company (1) Audit Committee Chairman (until his death on March 31, 2013). Steven J. granted under the Executive Stock Option Plan. The options became fully Quamme succeeded Sir Michael R. Jenkins as Audit Committee Chairman. vested in May 2008 and expired in May 2013. (2) Remuneration Committee Chairman (since September 24, 2012). (3) Nomination Committee Chairman (until his resignation on April 15, 2013). The program included 896,834 common shares, all of which have already Carlos Gulisano succeeded Christian Weyer as Nomination Committee been issued. Chairman. Pension and retirement benefits We do not maintain any defined benefit pension plans or any other employees The following table sets forth the other common share awards to our retirement programs for our employees or directors. executive directors, management and key employees since 2008 through Other common share awards to executive directors, management and key April 15, 2014. Number of underlying common shares awarded 976,211(1) 1,000,000(2) 500,000(3) 500,000(4) 500,000(6) % of issued common share capital approximately 2.2 Grant Exercise Vesting Expiration date December 15, 2008 price US$0.001 date December 15, 2012 date December 15, 2018 approximately 2.0 December 15, 2010 US$0.001 December 15, 2014 December 15, 2020 approximately 1.1 approximately 1.1 approximately 1.1 December 15, 2011 December 15, 2012 US$0.001 US$0.001 June 30, 2013 US$0.001 December 15, 2015 (5)December 15, 2016 December 31, 2015 December 15, 2021 December 15, 2022 December 31, 2019 (1) Dr. Carlos Gulisano holds 100,000 of such awards. (4) As of the date of this annual report, there are 64,000 awards that will not (2) As of the date of this annual report, there are 164,400 awards that will vest due to the relevant employees having left the Company before the not vest due to the relevant employees having left the Company before the vesting date. vesting date. (5) Certain programs contemplate different vesting dates, in each case before (3) As of the date of this annual report, there are 6,000 awards that will not December 15, 2016. vest due to the relevant employees having left the Company before the (6) The common shares will be awarded under this program provided certain vesting date. minimum financial and operational targets are met through 2015. 154 GeoPark 20F In addition to the awards described above under our Performance-Based Employee Long-Term Incentive Program and our Executive Stock Option Employee Long-Term Incentive Program, on August 31, 2011, we granted Plan authorize the Company to deposit any common shares they have an aggregate award of 90,000 common shares at an exercise price of received under these programs in our Employee Benefit Trust, or EBT. The EBT US$0.001 to certain of our former employees, of which 30,000 vested in 2012 is held to facilitate holdings and dispositions of those common shares by the and the remaining 60,000 vested in September 2013. In addition, on participants thereof. Under the terms of the EBT, each participant is entitled November 23, 2012, we granted awards of common shares at an exercise to receive any dividends we may pay which correspond to their common price of US$0.001 to each of James F. Park (450,000 common shares) and shares held by the trust, according to instructions sent by the Company to the Gerald E. O’Shaughnessy (270,000 common shares), in each case with a trust administrator. The trust provides that Mr. James F. Park is entitled to vesting date of November 23, 2015. vote all the common shares held in the trust. Value Creation Plan In July 2013, our remuneration committee established the “Value Creation Share Repurchase Program On October 29, 2013, we put into place an irrevocable, non-discretionary Plan,” or VCP, to give our executive officers and key management members share purchase program for the purchase of up to 400,000 of our common the opportunity to share in a percentage of the value created for shares, or the Purchase Program, for the account of our Employee Benefit shareholders in excess of a pre-determined share price target at the end Trust, or the EBT. The Purchase Program was in effect through December 31, of a performance period. Under the VCP, if as of December 31, 2015, 2013, and was managed by BTG Pactual Chile International Limited and our share price (defined as the average trading price of our common shares Oriel Securities Limited. The common shares purchased under the Purchase on the NYSE for the month of December 2015) exceeds US$13.66, VCP Program will be used to satisfy future awards under our employee long-term participants will receive an aggregate payment equal to 10% of the excess incentive programs. See “—Executive compensation.” above the market capitalization threshold generated by this share price (assuming that the share capital of the Company has remained at the same In November 2013, we purchased an aggregate of 50,000 common shares level as applicable at the time of grant of the VCP: 43,495,585 shares). at a purchase price between 5.40 and 5.45 GBP for the account of the EBT The award will be paid in common shares under our Performance-Based pursuant to the Purchase Program. Employee Long-Term Incentive Program. The award will vest 50% on December 31, 2015, and the remaining 50% on December 31, 2016. C. Board practices Notwithstanding the foregoing, 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 Overview Our board of directors is responsible for establishing our strategic goals, outstanding) used to calculate if the market capitalization threshold has ensuring that the necessary resources are in place to achieve these goals been met is subject to adjustment for any stock splits. and reviewing our management and financial performance. Our board of Potential dilution resulting from Performance-Based Employee Long-Term Incentive Program The percentage of total share capital that could be awarded to our executive directors directs and monitors the company in accordance with a framework 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 directors, management and key employees under the Performance-Based standards of business conduct and for ensuring that these, together with our Employee Long-Term Incentive Program would represent approximately 12% obligations to our shareholders, are understood throughout the company. of our issued common shares. However, as of the date of this annual report, we have awarded approximately 8.5% of our current total issued share capital (not including shares that may be issued under the VCP program). Employee Benefit Trust Our directors, senior management and key employees who have received Board composition Our bye-laws and board resolutions provide that the board of directors consist of a minimum of three and a maximum of nine members. All of our directors were elected at our annual shareholders’ meeting held on July 30, 2013, and their term expires on the date of our next annual shareholders’ option awards or common share awards under our Performance-Based meeting, to be held in 2014. The board of directors meets at least on a quarterly basis. GeoPark 20F 155 Committees of our board of directors Our board of directors has established an Audit Committee, a Remuneration and our shareholders. No member of the Remuneration Committee participates in any discussion about his or her own remuneration. Committee and a Nomination Committee. The composition and responsibilities of each committee are described below. Members serve on the Audit Committee for a period of three years. For the Remuneration Nomination committee The Nomination Committee is composed of three directors. The members and Nomination Committees, members serve on these committees until of the Nomination Committee are Mr. Gerald E. O’Shaughnessy, Mr. Carlos their resignation or until otherwise determined by our board of directors. Gulisano (who serves as Chairman of the committee) and Mr. Pedro Aylwin. In the future, our board of directors may establish other committees to assist with its responsibilities. Audit committee The Audit Committee is composed of three directors: Mr. Peter Ryalls, The Nomination Committee meets as required and its responsibilities include: (a) reviewing the structure, size and composition of the board of directors and making recommendations to the board of directors in respect of any required changes; (b) identifying, nominating and submitting for approval by Mr. Juan Cristóbal Pavez and Mr. Steven J. Quamme (who serves as Chairman the board of directors candidates to fill vacancies on the board of directors as of the committee). We have determined that Mr. Peter Ryalls and Mr. Juan and when they arise; (c) making recommendations to the board of directors Cristóbal Pavez are independent, as such term is defined under SEC rules with respect to the membership of the Audit Committee and Remuneration applicable to foreign private issuers. In accordance with NYSE rules, we expect Committee in consultation with the chairman of each committee; (d) to have a fully independent audit committee within one year of listing. reviewing outside directorships/commitments of non-executive directors; and (e) succession planning for directors and senior executives. The Audit Committee’s responsibilities include: (a) approving our financial statements; (b) reviewing financial statements and formal announcements relating to our performance; (c) assessing the independence, objectivity and Liability insurance We maintain liability insurance coverage for all of our directors and officers, effectiveness of our external auditors; (d) making recommendations for the level of which is reviewed annually. the appointment, re-appointment and removal of our external auditors and approving their remuneration and terms of engagement; (e) implementing and monitoring policy on the engagement of external auditors supplying D. Employees As of December 31, 2013, we had approximately 404 employees, of which non-audit services to us; (f) obtaining, at our expense, outside legal or other 193 were located in Chile, 109 were located in Colombia, 98 were located in professional advice on any matters within its terms of reference and securing Argentina and four were located in Brazil. This represented an increase of the attendance at its meetings of outsiders with relevant experience and 14% from December 31, 2012, which increase was largely attributable to the expertise if it considers it necessary; and (g) reviewing our arrangements for growth of our Colombian operations and new operations in our Tierra del our employees to raise concerns about possible wrongdoing in financial Fuego Blocks. reporting or other matters and the procedures for handling such allegations, and ensuring that these arrangements allow proportionate and independent investigation of such matters and appropriate follow-up action. The following table sets forth a breakdown of our employees by geographic segment for the periods indicated. Remuneration committee The Remuneration Committee is composed of three directors. The members of the remuneration committee are Mr. Juan Cristóbal Pavez (who serves Chile as Chairman of the committee), Mr. Peter Ryalls and Mr. Steve J. Quamme. The Remuneration Committee meets as required during the year, and its specific responsibilities include: (a) determining, in conjunction with the board of directors, the remuneration policy for the Chief Executive Officer, Colombia Argentina Brazil Total Year ended December 31, 2013 193 109 98 4 404 2012 163 98 92 — 353 2011 104 — 84 — 188 the Chairman, our executive directors and other members of executive From time to time, we also utilize the services of independent contractors management; (b) reviewing the performance of our executive directors and to perform various field and other services as needed. As of December 31, members of executive management; and (c) reviewing the design of the 2013, 11 of our employees were represented by labor unions or covered by share incentive plans that are submitted for approval to the board of directors collective bargaining agreements. We believe that relations with our employees are satisfactory. 156 GeoPark 20F E. Share ownership As of the date of this annual report, members of our board of directors and Benefit Trust.” Although Mr. Park has voting rights with respect to all the common shares held in the trust, Mr. Park disclaims beneficial ownership our senior management held as a group 28,497,744 of our common shares over those common shares. 498,915 of these common shares have been and 49.25% of our outstanding share capital. pledged pursuant to lending arrangements. The following table shows the share ownership of each member of our board by Cartica Management, LLC. The common shares reflected as being of directors and senior management as of the date of this annual report. held by Mr. Quamme include 8,189 common shares held by him personally. (3) Held through certain private investment funds managed and controlled Shareholder Gerald E. O’Shaughnessy(1) James F. Park(2) Steven J. Quamme(3) Juan Cristóbal Pavez(4) Carlos Gulisano Pedro Aylwin Peter Ryalls Augusto Zubillaga Gerardo Hinterwimmer Salvador Harambour Marcela Vaca Dimas Coelho Carlos Murut Salvador Minniti Jose Díaz Horacio Fontana Ruben Marconi Agustina Wisky Guillermo Portnoi Andrés Ocampo Pablo Ducci Common shares 7,533,907 7,441,269 9,699,161 2,887,130 117,281 131,431 45,451 * * * * * * * * * * * * * * Sub-total senior management ownership of less than 1% Total 642,114 28,497,744 Mr. Steven Quamme, one of our principal shareholders and a member of our Percentage of board of directors, is the Senior Managing Director of Cartica Management, outstanding LLC, and therefore may be deemed to have voting and investment power common shares 13.02 over the common shares of GeoPark held by Cartica Management, LLC. (4) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 9,326 common shares held by him personally. ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS A. Major shareholders The following table presents the beneficial ownership of our common shares as of the date of this annual report. 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) Other shareholders Total 1.11 Common shares 7,533,907 7,441,269 9,699,161 3,456,594 2,598,650 2,887,130 24,246,904 57,863,615 Percentage of outstanding common shares 13.02 12.86 16.76 5.97 4.49 4.99 41.90 100.0% 12.86 16.76 4.99 0.20 0.23 0.08 * * * * * * * * * * * * * * 49.25 (1) Held directly and indirectly through GP Investments LLP, Vidacos Nominees Limited and Globe Resources Group Inc. 922,482 of these * Indicates ownership of less than 1% of outstanding common shares. common shares have been pledged pursuant to lending arrangements. (1) Held directly and indirectly through GP Investments LLP, Vidacos (2) Held by Energy Holdings, LLC, which is controlled by James F. Park, Nominees Limited and Globe Resources Group Inc., all of which are controlled a member of our Board of Directors. The number of common shares held by Mr. O’Shaughnessy. 922,482 of these common shares have been pledged by Mr. Park does not reflect the 822,702 common shares held as of the date pursuant to lending arrangements. of this annual report in the employee benefit trust described under “Item 6. (2) Held by Energy Holdings, LLC, which is controlled by James F. Park, a Directors, Senior Management and Employees—B. Compensation— member of our Board of Directors. The number of common shares held by Employee Benefit Trust.” Although Mr. Park has voting rights with respect Mr. Park does not reflect the 822,702 common shares held as of the date of to all the common shares held in the trust, Mr. Park disclaims beneficial this annual report in the employee benefit trust described under “Item 6. ownership over those common shares. 498,915 of these common shares Directors, Senior Management and Employees—B. Compensation—Employee have been pledged pursuant to lending arrangements. GeoPark 20F 157 (3) Held through certain private investment funds managed and controlled the boards of each of GeoPark Chile and GeoPark TdF will consist of four by Cartica Management, LLC. The common shares reflected as being held directors; as long as LGI holds at least 5% of the voting shares of GeoPark by Mr. Quamme include 8,189 common shares held by him personally. Chile or GeoPark TdF, as applicable, LGI has the right to elect one director and Mr. Steven Quamme, one of our principal shareholders and a member of our such director’s alternate, while the remaining directors, and alternates, are board of directors, is the Senior Managing Director of Cartica Management, elected by us. Additionally, the agreements require the consent of LGI or its LLC, and therefore may be deemed to have voting and investment power appointed director in order for GeoPark Chile or GeoPark TdF, as applicable, over the common shares of GeoPark held by Cartica Management, LLC. to be able to take certain actions, including, among others: making any (4) IFC Equity Investments voting decisions are made through a portfolio decision to terminate or permanently or indefinitely suspend operations in or management process which involves consultation from investment officers, surrender our blocks in Chile (other than as required under the terms of the credit officers, managers and legal staff. relevant CEOP for such blocks); selling our blocks in Chile to our affiliates; (5) Held through various funds managed by Moneda A.F.I. (Administradora making any change to the dividend, voting or other rights that would give de Fondos de Inversión), an asset manager. preference to or discriminate against the shareholders of these companies; (6) Held through Socoservin Overseas Ltd, which is controlled by Juan entering into certain related party transactions; and creating a security Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez interest over our blocks in Chile (other than in connection with a financing include 9,326 common shares held by him personally. that benefits our Chilean subsidiaries). The LGI Chile Shareholders’ Principal shareholders do not have any different or special voting rights in decides to sell its shares in GeoPark Chile or GeoPark TdF, as applicable, comparison to any other common shareholder. the transferring shareholder must make an offer to sell those shares to the Agreements also provide that: (i) if LGI or either Agencia or GeoPark Chile Prior to our initial public offering on the NYSE in February of 2014, our to a third party is subject to tag-along and drag-along rights, and the non- principal shareholders were Gerald E. O’Shaughnessy (17.18%), James F. Park transferring shareholder has the right to object to a sale to the third-party (16.32%), Cartica Management, LLC (11.36%), IFC Equity Investments, if it considers such third-party to be not of a good reputation or one of other shareholder before selling them to a third party; and (ii) any sale (7.88%) and Moneda A.F.I (5.11%). our direct competitors. We and LGI also agreed to vote our common shares or otherwise cause GeoPark Chile or GeoPark TdF, as applicable, to On February 12, 2014, we completed our initial public offering and listed declare dividends only after allowing for retentions to meet anticipated our common shares on the New York Stock Exchange. In the initial public future investments, costs and obligations. See “Item 4. Information on offering, we issued 13,999,700 common shares (including the overallotment the Company—B. Business overview—Significant agreements—Agreements option granted to and exercised by the underwriters). Pursuant to the with LGI— LGI Chile Shareholders’ Agreements.” offering, 5,927,571 shares were issued to certain of our principal shareholders, as follows: James F. Park purchased 285,000 common shares, Cartica Management, LLC purchased 4,714,000 common shares, and Moneda LGI Colombia Agreements On December 18, 2012, we, Agencia, GeoPark Colombia and LGI entered purchased 928,571 common shares, as reflected in the table above. B. Related party transactions We have entered into the following transactions with related parties: LGI Chile Shareholders’ Agreements In 2010, we formed a strategic partnership with LGI to acquire and develop into the LGI Colombia Shareholders’ Agreement and a subscription share agreement, pursuant to which LGI acquired a 20% interest in GeoPark 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’ jointly upstream oil and gas projects in Latin America. In 2011, LGI acquired a Agreement in respect of our oil and gas business in Colombia. We refer to 20% equity interest in GeoPark Chile and a 14% equity interest in GeoPark the LGI Colombia Shareholders’ Agreement and the LGI Colombia Members’ TdF, for a total consideration of US$148.0 million, plus additional equity Agreement collectively as the LGI Colombia Agreements. The LGI Colombia funding of US$18.0 million through 2014. On May 20, 2011, in connection Agreements provide that the board of GeoPark Colombia will consist of four with LGI’s investment in GeoPark Chile, we and LGI entered into the LGI Chile directors; as long as LGI holds at least 14% of GeoPark Colombia, LGI has Shareholders’ Agreements, setting forth our and LGI’s respective rights the right to elect one director and such director’s alternate, while the and obligations in connection with LGI’s investment in our Chilean oil and gas remaining directors, and alternates, are elected by us. Additionally, the LGI business. Specifically, the LGI Chile Shareholders’ Agreements provide that Colombia Agreements require the consent of LGI or the LGI appointed 158 GeoPark 20F director for GeoPark Colombia to be able to take certain actions, including, amount owed on the performance bond because minimum work obligations among others: making any decision to terminate or permanently or imposed by the terms of the bond have been met. indefinitely suspend operations in or surrender our blocks in Colombia (other than as required under the terms of the relevant concessions for such The LGI Stand-by Letters of Credit initially expired on March 31, 2013, and blocks); creating a security interest over our blocks in Colombia; approving were renewed until May 18, 2016, and the applicable interest rate is 1.5%. As of GeoPark Colombia’s annual budget and work programs and the of December 31, 2013, the aggregate outstanding amount attributable to mechanisms for funding any such budget or program; entering into any GeoPark’s share under the LGI Stand-by Letters of Credit was US$52.3 million. borrowings other than those provided in an approved budget or incurred in the ordinary course of business to finance working capital needs; granting any guarantee or indemnity to secure liabilities of parties other than those IFC Subscription and Shareholders’ Agreement On February 7, 2006, in order to finance the exploration, development and of our Colombian subsidiaries; changing the dividend, voting or other rights exploitation of our blocks in Chile and Argentina and the acquisition of that would give preference to or discriminate against the shareholders additional exploration, development and exploitation blocks in Latin America, of GeoPark Colombia; entering into certain related party transactions; and we, IFC and Gerald E. O’Shaughnessy and James F. Park, as Lead Investors, disposing of any material assets other than those provided for in an approved entered into an agreement, or the IFC Subscription and Shareholders’ budget and work program. The LGI Colombia Agreements also provide that: Agreement, pursuant to which IFC agreed to subscribe and pay for 2,507,161 (i) if either we or LGI decide to sell our respective shares in GeoPark Colombia, of our common shares, representing approximately 10.5% of our then- the transferring shareholder must make an offer to sell those shares to the outstanding common shares, at an aggregate subscription price of US$10.0 other shareholder before selling those shares to a third party; and (ii) any sale million (or approximately US$3.99 per common share). to a third party is subject to tag-along and drag-along rights, and the non- transferring shareholder has the right to object to a sale to the third-party We agreed, for so long as IFC is a shareholder in the company, among if it considers such third-party to be not of a good reputation or one of other things, to: ensure that our operations are in compliance with certain our direct competitors. We and LGI also agreed to vote our common shares environmental and social guidelines; appoint and maintain a technically or otherwise cause GeoPark Colombia to declare dividends only after qualified individual to be responsible for the environmental and social allowing for retentions for approved work programs and budgets, capital management of our activities; maintain certain forms of insurance coverage, adequacy and tied surplus requirements of GeoPark Colombia, working including coverage for public liability and director’s and officer’s liability capital requirements, banking covenants associated with any loan entered reasonably acceptable to IFC, and in respect of certain of our operations; into by GeoPark Colombia or our other Colombian subsidiaries and not undertake certain prohibited activities; and ensure that no prohibited operational requirements. See “Item 4. Information on the Company—B. payments are made by us or on our or the Lead Investors’ behalf, in respect Business overview—Significant agreements—Agreements with LGI—LGI of our operations. Colombia Agreements.” We also agreed to provide to IFC, within 30 days of the end of the first half 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 GeoPark Chile and a 14% equity interest in GeoPark TdF for US$148.0 million. for the period, a comprehensive report on the progress of the exploration, development and exploitation of our blocks in Latin America and a statement LGI provided to GeoPark TdF standby letters of credit for an amount of of all related party transactions during the period, with a certification by a US$31.6 million (corresponding to its pro rata share in GeoPark TdF) and for company officer that these were on an arm’s-length basis; within 90 days of an additional amount of US$52.3 million (or the additional amount), the end of our fiscal year, copies of our audited consolidated financial resulting in an aggregate of US$84.0 million in standby letters of credit, statements for the year (prepared under IFRS), a management letter from our or the LGI Stand-by Letters of Credit, to partially secure the US$101.4 million auditors in respect of our financial control procedures, accounting and performance bond required by the Chilean government to guarantee management information systems and any litigation, an annual monitoring GeoPark TdF’s obligations with respect to the first period’s minimum work report confirming compliance with national or local requirements and the program under the Tierra del Fuego CEOPs. The remaining US$17.4 million environmental and social requirements mandated by the agreement, a report was provided by GeoPark. All costs and liabilities regarding the additional indicating any payments in the year to any governmental authority in amount shall be paid by GeoPark. GeoPark has already applied to the Ministry connection with the documents governing our Chilean and Argentine blocks of Energy for an aggregate reduction of approximately US$35 million in the and certificates of insurance, with a certificate of our insurer confirming that GeoPark 20F 159 effectiveness of our policies and payment of all applicable premiums; within injunction is lifted. According to the terms of the Court’s injunction, the 45 days before each fiscal year begins, a proposed annual business plan ANP will first need to take certain actions, such as conducting studies and budget for the upcoming year; within 3 days after its occurrence, that prove that drilling unconventional resources will not contaminate the notification of any incident that had or may reasonably be expected to have dams and aquifers in the region. On February 21, 2014, GeoPark Brazil an adverse effect on the environment, health or safety; copies of notices, requested that the board of the ANP suspend the execution of the concession reports or other communications between us and our board of directors agreement (which entails delivery of the financial guarantee and performance or shareholders; and, within five days of receipt thereof, copies of any guarantee and payment of the signing bonus) for six months with a possible reports, correspondence, documentation or notices from any third-party, extension of an additional six months, or until a firm court decision is reached governmental authority or state-owned company that could reasonably be that does not prevent GeoPark Brazil from entering into the concession expected to materially impact our operations. Mr. O’Shaughnessy and agreement. On April 16, 2014, the ANP’s Board enacted a resolution stating Mr. Park have also agreed to procure that shareholders holding 51% of our that all proceedings related to the award of the concession of Block PN-T-597 common shares cause us to comply with the covenants above. to GeoPark Brazil were suspended. Executive Directors’ Service Agreements We have entered into service contracts with certain of our executive directors. Dividends and dividend policy Holders of common shares will be entitled to receive dividends, if any, paid See “Item 6. Directors, Senior Management and Employees—B. on the common shares. Compensation— Executive compensation—Executive directors’ contracts.” C. Interests of Experts and Counsel Not applicable. ITEM 8. FINANCIAL INFORMATION 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 operations for the development and growth of our business. Accordingly, we do not expect to pay cash dividends on our common shares in the foreseeable future. Because we are a holding company with no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries. The terms A. Consolidated statements and other financial information of our indebtedness may restrict us from paying dividends, or restrict our subsidiaries from paying dividends to us. Financial statements See “Item 18. Financial Statements,” which contains our audited financial Under the Bermuda Companies Act, we may not declare or pay a dividend statements prepared in accordance with IFRS. if there are reasonable grounds for believing that we are, or would after the Legal proceedings From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than our liabilities. We do not presently have any reasonable grounds for believing that, if we were to declare or pay a dividend on our common shares outstanding, we would employment, commercial, environmental, safety and health matters. For thereafter be unable to pay our liabilities as they became due or that the example, from time to time, we receive notice of environmental, health realizable value of our assets would thereafter be less than our liabilities. and safety violations. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated Additionally, any decision to pay dividends in the future, and the amount financial position, results of operations or liquidity. of any distributions, is at the discretion of our board of directors and our shareholders, and will depend on many factors, such as our results of In Brazil, GeoPark Brazil is currently a party to a legal proceeding related to operations, financial condition, cash requirements, prospects and other the concession agreement of Block PN-T-597 that the ANP initially awarded to factors. See “Item 3. Key Information—D. Risk factors—Risks related to our GeoPark Brazil in the 12th oil and gas bidding round. As a result of a class common shares—We have never declared or paid, and do not intend to action filed by the Federal Prosecutor’s Office, an injunction was issued by a pay in the foreseeable future, cash dividends on our common shares, and, Brazilian Federal Court against the ANP, the Federal Government and GeoPark consequently, your only opportunity to achieve a return on your investment Brazil on December 13, 2013. Due to the injunction GeoPark Brazil could not is if the price of our stock appreciates” and “—We are a holding company proceed to execute the concession agreement, and cannot do so until the dependent upon dividends from our subsidiaries, which may be limited by 160 GeoPark 20F law and by contract from making distributions to us, which would affect our The table below presents, for the periods indicated, the annual, quarterly ability to pay dividends on the common shares,” as well as “Item 10. and monthly high and low closing prices (in US$) of our common shares on Additional Information—B. Memorandum of association and bye-laws.” the NYSE. B. Significant changes A discussion of the significant changes in our business can be found under “Item 4. Information on the Company—A. History and development of the company— General—Recent Developments.” ITEM 9. THE OFFER AND LISTING A. Offering and listing details Not applicable. B. Plan of distribution Not applicable. C. Markets On February 6, 2014 we completed our initial public offering and listed our Annual price history 2014 (from February 7 through April 25, 2014) Quarterly price history 2014 1st Quarter (from February 7, 2014) 2nd Quarter (through April 25, 2014) Monthly price history February 2014 common shares on the New York Stock Exchange, or NYSE. For information (from February 7, 2014) regarding the price history of our common shares, see “—A. Offering and listing details.” March 2014 April 2014 (through April 25, 2014) 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 Source: Bloomberg symbol “GPK” until February 19, 2014, and, since 2009, have been admitted to trade on the Santiago Offshore Stock Exchange (Bolsa Off Shore de la Bolsa de Comercio de Santiago) in Chile. We intend to de-register from the Santiago D. Selling shareholders Not applicable. Offshore Stock Exchange as soon as practicable. Common shares Average daily High Low trading volume (US$ per share) (in shares) 8.40 6.45 69,138 8.10 8.40 8.05 8.10 8.40 6.45 78,469 6.76 50,477 6.45 7.07 133,375 39,250 6.76 50,477 E. Dilution Not applicable. F. Expenses of the issue Not applicable. ITEM 10. ADDITIONAL INFORMATION A. Share capital Not applicable. B. Memorandum of association and bye-laws The following description of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws. GeoPark 20F 161 General We are an exempted company with limited liability incorporated under any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. Holders of common shares the laws of Bermuda with registration number 33273 from the Registrar have no redemption, sinking fund, conversion, exchange or other of Companies. The rights of our shareholders will be governed by Bermuda subscription rights. In the event of our liquidation, the holders of common law and by our memorandum of association and bye-laws. Bermuda shares are entitled to share equally and ratably in our assets, if any, company law differs in some material respects from the laws generally remaining after the payment of all of our debts and liabilities, subject to applicable to Delaware corporations. Below is a summary of some of those any liquidation preference on any outstanding preference shares. material differences. Because the following statements are summaries, they do not discuss all Board composition Our bye-laws provide that our board of directors will determine the size aspects of Bermuda law that may be relevant to us and to our shareholders. of the board, provided that it shall be not be composed of fewer than three directors. Our board of directors currently consists of seven directors. 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 Election and removal of directors Our bye-laws preserve the staggered board provisions in effect prior to per share. As of the date of this annual report, there are 57,863,615 common our delisting from AIM until the annual general meeting following the listing shares outstanding. All of our issued and outstanding common shares are of the common shares on the NYSE. From and after the date of such fully paid and nonassessable. We also have an employee incentive program, annual general meeting, our directors shall hold office for such term as the pursuant to which we have granted share awards to our senior management shareholders shall determine or, in the absence of such determination, and certain key employees. See “Item 6. Directors, Senior Management until the next annual general meeting or until their successors are elected or and Employees.” appointed or their office is otherwise vacated. Directors whose office has expired may offer themselves for re-election at each election of the directors. 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 Under our bye-laws, a director may be removed by a resolution adopted by the terms of issue of the shares of that class) may, whether or not the by 65% or more of the votes cast by shareholders who (being entitled to Company is being wound-up, be varied with the consent in writing of do so) vote in person or by proxy at any general meeting of the shareholders the holders of at least two-thirds of the issued shares of that class or with the in accordance with the provisions of our bye-laws. Notice convened for sanction of a resolution passed by a majority of the votes cast at a separate the purpose of removing the director, containing a statement of the intention general meeting of the holders of the shares of the class at which meeting to do so, must be served on such director not less than 14 days before the necessary quorum shall be two persons at least holding or representing the meeting. 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 Any vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director in his or the shares of that class, be deemed to be varied by the creation or issue of her place or, in the absence of any such election, by the board of directors. further shares ranking pari passu therewith. Any other vacancy, including a newly created directorship, may be filled by our board of directors. Our bye-laws give our board of directors the power to issue any unissued shares of the company on such terms and conditions as it may determine, subject to the terms of the bye-laws and any resolution of the shareholders to the contrary. Common shares Holders of our common shares are entitled to one vote per share on all Proceedings of board of directors Our bye-laws provide that our business shall be managed by or under the direction of our board of directors. Our board of directors may act by the affirmative vote of a majority of the directors present at a meeting at which a quorum is present. The quorum necessary for the transaction of business at meetings of the board of directors shall be the presence of a majority of the matters submitted to a vote of holders of common shares. Subject to board of directors from time to time. preferences that may be applicable to any issued and outstanding preference shares, holders of common shares are entitled to receive such dividends, if 162 GeoPark 20F Duties of directors Under Bermuda common law, members of a board of directors owe a Interested directors Pursuant to our bye-laws, a director shall declare the nature of his interest fiduciary duty to the Company to act in good faith in their dealings with or in any contract or arrangement with the company as required by on behalf of the company, and to exercise their powers and fulfill the duties the Bermuda Companies Act. A director so interested shall not, except in of their office honestly. This duty has the following essential elements: particular circumstances set out in our bye-laws, be entitled to vote or (1) a duty to act in good faith in the best interests of the company; (2) a duty be counted in the quorum at a meeting in relation to any resolution in which not to make a personal profit from opportunities that arise from the office he has an interest, which is to his knowledge, a material interest (otherwise of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise than by virtue of his interest in shares or debentures or other securities powers for the purpose for which such powers were intended. The Bermuda of or otherwise in or through the company). In addition, the director will not Companies Act also imposes a duty on directors of a Bermuda company, be liable to us for any profit realized from the transaction. In contrast, to act honestly and in good faith, with a view to the best interests of the under Delaware law, such a contract or arrangement is voidable unless it is company, and to exercise the care, diligence and skill that a reasonably approved by a majority of disinterested directors or by a vote of shareholders, prudent person would exercise in comparable circumstances. In addition, in each case if the material facts as to the interested director’s relationship the Bermuda Companies Act imposes various duties on directors with respect or interests are disclosed or are known to the disinterested directors or to certain matters of management and administration of the company. shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director The Bermuda Companies Act provides that in any proceedings for negligence, could be held liable for a transaction in which such director derived an default, breach of duty or breach of trust against any director, if it appears improper personal benefit. to a court that such officer is or may be liable in respect of the negligence, 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, Indemnification of directors and officers Bermuda law provides generally that a Bermuda company may indemnify including those connected with his appointment, he ought fairly to be its directors and officers against any loss arising from or liability which by excused for the negligence, default, breach of duty or breach of trust, that virtue of any rule of law would otherwise be imposed on them in respect of court may relieve him, either wholly or partly, from any liability on such terms any negligence, default, breach of duty or breach of trust except in cases as the court may think fit. This provision has been interpreted to apply only where such liability arises from fraud or dishonesty of which such director to actions brought by or on behalf of the company against the directors. or officer may be guilty in relation to the company. By comparison, under Delaware law, the business and affairs of a corporation Our bye-laws provide that we shall indemnify our officers and directors in are managed by or under the direction of its board of directors. In exercising respect of their actions and omissions, except in respect of their fraud or their powers, directors are charged with a duty of care and a duty of loyalty. dishonesty, or to recover any gain, personal profit or advantage to which such The duty of care requires that directors act in an informed and deliberate director is not legally entitled, and (by incorporation of the provisions of the manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably available to them. The duty Bermuda Companies Act) that we may advance monies to our officers and directors for costs, charges and expenses incurred by our officers and directors of care also requires that directors exercise care in overseeing the conduct in defending any civil or criminal proceeding against them on the condition of corporate employees. The duty of loyalty is the duty to act in good faith, that the officers and directors repay the monies if any allegation of fraud or not out of self-interest, and in a manner which the director reasonably dishonesty is proved against them provided, however, that, if the Bermuda believes to be in the best interests of the shareholders. A party challenging Companies Act requires, an advancement of expenses shall be made only upon the propriety of a decision of a board of directors bears the burden of delivery to the Company of an undertaking ,by or on behalf of such indemnitee, rebutting the presumptions afforded to directors by the “business judgment to repay all amounts so advanced if it shall ultimately be determined rule.” If the presumption is not rebutted, the business judgment rule attaches by final judicial decision from which there is no further right to appeal that to protect the directors and their decisions. Where, however, the presumption such indemnitee is not entitled to be indemnified for such expenses is rebutted, the directors bear the burden of demonstrating the fairness under this Bye-law or otherwise. Our bye-laws provide that the company and of the relevant transaction. Notwithstanding the foregoing, Delaware courts the shareholders waive all claims or rights of action that they might have, subject directors’ conduct to enhanced scrutiny in respect of defensive individually or in right of the company, against any of the company’s directors actions taken in response to a threat to corporate control and approval of a or officers for any act or failure to act in the performance of such director’s or transaction resulting in a sale of control of the corporation. officer’s duties, except in respect of any fraud or dishonesty. GeoPark 20F 163 Meetings of shareholders Under Bermuda law, a company is required to convene the annual general Business combinations A Bermuda company may engage in a business combination pursuant to meeting of shareholders each calendar year, unless the shareholders in a a tender offer, amalgamation, merger or sale of assets. The amalgamation or general meeting, elect to dispense with the holding of annual general merger of a Bermuda company with another company generally requires meetings. Under Bermuda law and our bye-laws, a special general meeting of the amalgamation or merger agreement to be approved by the company’s shareholders may be called by the board of directors or the chairman and board of directors and by its shareholders. Shareholder approval is not may be called upon the requisition of shareholders holding not less than 10% required where (a) a holding company and one or more of its wholly-owned of the paid-up capital of the company carrying the right to vote at general subsidiary companies amalgamate or merge or (b) two or more wholly- meetings of shareholders. owned subsidiary companies of the same holding company amalgamate or merge. Under the Bermuda Companies Act (save for such “short-form Our bye-laws provide that, at any general meeting of the shareholders, the amalgamations”), unless a company’s bye-laws provide otherwise, presence in person or by proxy of two or more shareholders representing in the approval of 75% of the shareholders voting at a meeting is required excess of 50% of the total issued voting shares of the company shall to approve the amalgamation or merger agreement, and the quorum for constitute a quorum for the transaction of business unless the company only such meeting must be two persons holding or representing more than has one shareholder, in which case such shareholder shall constitute a one-third of the issued shares of the company. Our bye-laws provide that an quorum. Unless otherwise required by law or by our bye-laws, shareholder amalgamation or merger will require the approval of our board of directors action requires a resolution adopted by a majority of votes cast by and of our shareholders by a resolution adopted by 65% or more of the shareholders at a general meeting at which a quorum is present. votes cast by shareholders who (being entitled to do so) vote in person or Shareholder proposals Under Bermuda law, shareholders holding at least 5% of the total voting by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or rights of all the shareholders having at the date of the requisition a right corporation, a shareholder who is not satisfied that fair value has been to vote at the meeting to which the requisition relates or any group offered for such shareholder’s shares may, within month of the notice of the composed of at least 100 or more shareholders may require a proposal to shareholders meeting, apply to the Supreme Court of Bermuda to appraise be submitted to an annual general meeting of shareholders. Under our the value of those shares. bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders Under the Bermuda Companies Act, we are not required to seek the approval must provide (among other things) advance notice, as set out in our of our shareholders for the sale of all or substantially all of our assets. bye-laws. Shareholders may only propose a person for election as a director However, Bermuda courts will view decisions of the English courts as highly at an annual general meeting. persuasive and English authorities suggest that such sales do require shareholder approval. Our bye-laws provide that the directors shall manage Shareholder action by written consent Our bye-laws provide that, except for the removal of auditors and directors, the business of the Company and may exercise all such powers as are not, by the Bermuda Companies Act or by these Bye-laws, required to be any actions which shareholders may take at a general meeting of exercised by the Company in general meeting and may pay all expenses shareholders may be taken by the shareholders through the unanimous incurred in promoting and incorporating the company and may exercise all written consent of the shareholders who would be entitled to vote on the the powers of the Company including, but not by way of limitation, the matter at the general meeting. 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 Amendment of memorandum of association and bye-laws Our memorandum of association and bye-laws may be amended with the of the Company and to issue debentures and other securities, whether outright or as collateral security for any debt, liability or obligation of the approval of a majority of our board of directors and by a resolution by a Company or any other persons. majority 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 in Under Bermuda law, where an offer is made for shares of a company and, accordance with the provisions of the bye-laws. within four months of the offer, the holders of not less than 90% of the shares not owned by the offeror, its subsidiaries or their nominees accept such offer, the offeror may by notice require the non-tendering shareholders to transfer their shares on the terms of the offer. Dissenting shareholders do not have 164 GeoPark 20F express appraisal rights but are entitled to seek relief (within one month of association and any amendments thereto. The shareholders have the the compulsory acquisition notice) from the court, which has power to make additional right to inspect the bye-laws of the company, minutes of general such orders as it thinks fit. Additionally, where one or more parties hold meetings of shareholders and the company’s audited financial statements. not less than 95% of the shares of a company, such parties may, pursuant to The company’s audited financial statements must be presented at the annual a notice given to the remaining shareholders, acquire the shares of such general meeting of shareholders, unless the board and all the shareholders remaining shareholders. Dissenting shareholders have a right to apply agree to the waiving of the audited financials. The company’s share register to the court for appraisal of the value of their shares within one month of the is open to inspection by shareholders and by members of the general compulsory acquisition notice. If a dissenting shareholder is successful in public without charge. A company is required to maintain its share register in obtaining a higher valuation, that valuation must be paid to all shareholders Bermuda but may, subject to the provisions of the Bermuda Companies Act, being squeezed out. Dividends and repurchase of shares Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law. Under Bermuda law, a company may not declare or pay a dividend if there are establish a branch register outside of Bermuda. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records. Registrar or transfer agent A register of holders of the common shares is maintained by Coson Corporate reasonable grounds for believing that the company is, or would after the Services Limited in Bermuda, and a branch register is maintained in the payment be, unable to pay its liabilities as they become due or the realizable United States by Computershare Trust Company, N.A., who serves as branch value of its assets would thereby be less than its liabilities. Under Bermuda registrar and transfer agent. law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due. C. Material contracts See “Item 4. Information on the Company—B. Business overview—Significant Shareholder suits 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 in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the agreements.” D. Exchange controls Not applicable. E. Taxation The following summary contains a description of certain Colombian and U.S. company or illegal, or would result in the violation of the company’s federal income tax consequences of the acquisition, ownership and disposition memorandum of association or bye-laws. Furthermore, consideration of preferred shares. The summary is based upon the tax laws of Colombia and would be given by a Bermuda court to acts that are alleged to constitute a regulations thereunder and on the tax laws of the United States and regulations fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it. thereunder as of the date hereof, which are subject to change. Bermuda tax considerations At the date of this annual report, there is no Bermuda income or profits When the affairs of a company are being conducted in a manner which is tax, withholding tax, capital gains tax, capital transfer tax, estate duty or oppressive or prejudicial to the interests of some part of the shareholders, inheritance tax payable by us or by our shareholders in respect of our one or more shareholders may apply under the Bermuda Companies common shares. We have obtained an assurance from the Minister of Finance Act for an order of the Supreme Court of Bermuda, which may make such of Bermuda under the Exempted Undertakings Tax Protection Act 1966 order as it sees fit, including an order regulating the conduct of the that, in the event that any legislation is enacted in Bermuda imposing any company’s affairs in the future or ordering the purchase of the shares of tax computed on profits or income, or computed on any capital asset, gain any shareholders by other shareholders or by the company. or appreciation or any tax in the nature of estate duty or inheritance tax, Access to books and records and dissemination of information Members of the general public have a right to inspect the public documents such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our common shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is of a company available at the office of the Registrar of Companies in payable by us in respect of real property owned or leased by us in Bermuda. Bermuda. These documents include the company’s memorandum of We pay annual Bermuda government fees. GeoPark 20F 165 Material U.S. federal income tax considerations The following is a description of the material U.S. federal income tax A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal income tax purposes that is: consequences to U.S. Holders (as defined below) of owning and disposing • a citizen or individual resident of the United States; of our common shares. This discussion is not a comprehensive description • a corporation, or other entity taxable as a corporation, created or organized of all tax considerations that may be relevant to a particular person’s decision in or under the laws of the United States, any state therein or the District of to acquire our common shares. This discussion applies only to a U.S. Holder Columbia; or that holds our common shares as capital assets for tax purposes. In addition, • an estate or trust the income of which is subject to U.S. federal income it does not describe all of the tax consequences that may be relevant taxation regardless of its source. in light of the U.S. Holder’s particular circumstances, including alternative minimum tax and Medicare contribution tax consequences and differing tax This discussion assumes that we are not, and will not become, a passive consequences applicable to a U.S. Holder subject to special rules, such as: foreign investment company, as described below. • certain financial institutions; • a dealer or trader in securities who uses a mark-to-market method of tax accounting; Taxation of distributions Distributions paid on our common shares will generally be treated as • a person holding common shares as part of a straddle, wash sale or dividends to the extent paid out of our current or accumulated earnings conversion transaction or entering into a constructive sale with respect to and profits (as determined under U.S. federal income tax principles). Because the common shares; we do not maintain calculations of our earnings and profits under U.S. • a person whose functional currency for U.S. federal income tax purposes is federal income tax principles, it is expected that distributions will generally not the U.S. dollar; be reported to U.S. Holders as dividends. Dividends paid by qualified foreign • a partnership or other entities classified as partnerships for U.S. federal corporations to certain non-corporate U.S. Holders may be taxable at income tax purposes; favorable rates. A foreign corporation is treated as a qualified foreign • a tax-exempt entity, including an “individual retirement account” or “Roth corporation with respect to dividends paid on stock that is readily tradable IRA;” on a securities market in the United States, such as the NYSE, which has • a person that owns or is deemed to own 10% or more of our voting stock; approved the listing of our common shares for trading. Non-corporate U.S. • a person who acquired our shares pursuant to the exercise of an employee Holders should consult their tax advisers to determine whether the favorable stock option or otherwise as compensation; or rate will apply to dividends they receive and whether they are subject to • a person holding common shares in connection with a trade or business any special rules that limit their ability to be taxed at this favorable rate. conducted outside of the United States. If an entity that is classified as a partnership for U.S. federal income received, will be treated as foreign-source income to U.S. Holders tax purposes holds common shares, the U.S. federal income tax treatment and will not be eligible for the dividends-received deduction generally of a partner will generally depend on the status of the partner and upon the activities of the partnership. Partnerships holding common shares and available to U.S. corporations under the Code with respect to dividends paid by domestic corporations. A dividend generally will be included in a U.S. Holder’s income when 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. 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 This discussion is based on the Internal Revenue Code of 1986, as amended, shares will be capital gain or loss, and will be long-term capital gain or loss or the Code, administrative pronouncements, judicial decisions, and final, if the U.S. Holder held our common shares for more than one year. Long-term temporary and proposed Treasury regulations, all as of the date hereof, any capital gain of a non-corporate U.S. Holder is generally taxed at preferential of which is subject to change, possibly with retroactive effect. U.S. Holders rates. The deductibility of capital losses is subject to limitations. The amount should consult their tax advisers concerning the U.S. federal, state, local and of the gain or loss will equal the difference between the U.S. Holder’s foreign tax consequences of owning and disposing of our common shares in tax basis in the common shares disposed of and the amount realized on the their particular circumstances. disposition. This gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. 166 GeoPark 20F Passive foreign investment company rules We believe that we were not a “passive foreign investment company,” or Chilean tax on transfers of shares In September 2012, Article 10 of the Chilean Income Tax Law Decree Law PFIC, for U.S. federal income tax purposes for 2013, and we do not expect to No. 824 of 1974, or the indirect transfer rules, were enacted, and impose taxes be a PFIC in the foreseeable future. However, because the composition of on the indirect transfer of shares, equity rights, interests or other rights in our income and assets will vary over time, there can be no assurance that we the equity, control or profits of a Chilean entity as well as transfers of other will not be a PFIC for any taxable year. The determination of whether we assets and property of permanent establishments or other businesses in are a PFIC is made annually and is based upon the composition of our income Chile, or the Chilean Assets. and assets (including the income and assets of, among others, entities in which we hold at least a 25% interest), and the nature of our activities. The indirect transfer rules apply to sales of shares of an entity: • If such entity is an offshore holding company located in a black-listed tax If we were a PFIC for any taxable year during which a U.S. Holder held our haven jurisdiction as determined by Chilean tax law, or a black-listed common shares, gain recognized by a U.S. Holder on a sale or other jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean disposition (including certain pledges) of our common shares would resident holds 5% or more of such entity, or such entity’s rights to equity, generally be allocated ratably over the U.S. Holder’s holding period for the control or profits, or 50% or more of such entity’s rights to equity or profits common shares. The amounts allocated to the taxable year of the sale or are held by residents in black-listed jurisdictions; or other disposition and to any year before we became a PFIC would be taxed • the shares or rights transferred represent 10% or more of the offshore as ordinary income. The amount allocated to each other taxable year holding company (considering dispositions by related persons and over the would be subject to tax at the highest rate in effect for individuals or preceding 12-month period) and the underlying Chilean Assets indirectly corporations for that year, as appropriate, and an interest charge would be transferred, in the proportion indirectly owned by the seller, (a) are valued in imposed. Further, to the extent that any distribution received by a U.S. an amount equal to or higher than UTA 210,000 (approximately US$200 Holder on its common shares exceeds 125% of the average of the annual million) (adjusted by the Chilean inflation unit of reference) or (b) represent distributions on the shares received during the preceding three years or 20% or more of the market value of the interest held by such seller in such the U.S. Holder’s holding period, whichever is shorter, that distribution would offshore holding company. be subject to taxation in the same manner as gain, as described immediately above. Certain elections may be available that would result in alternative As a result of these rules, a capital gain tax of 35% will be applied by the treatments (such as mark-to-market treatment) of our common shares. Chilean tax authorities to the sale of any of our common shares if either of U.S. Holders should consult their tax advisers to determine whether any of the above alternative are met. This rate might be subject to change in the these elections would be available and, if so, what the consequences of the short term. See “Item 4. Information on the Company—Business Overview— alternative treatments would be in their particular circumstances. Regulation of the oil and gas industry—Chile”. Information reporting and backup withholding Payments of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries generally are As of December 31, 2013, our Chilean Assets represented more than UTA 210,000 and represent more than 20% of our market value. subject to information reporting and may be subject to backup withholding The 35% rate is calculated pursuant to one of the following methods, as unless (1) the U.S. Holder is a corporation or other exempt recipient or determined by the seller: (2) in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup • the sale price of the shares minus the acquisition cost of such shares, withholding. The amount of any backup withholding from a payment to multiplied by the percentage or proportion of the part of the underlying a U.S. Holder will be allowed as a credit against the holder’s U.S. federal Chilean Assets’ fair market value (which assets are deemed to be “indirectly income tax liability and may entitle it to a refund, provided that the required transferred” by virtue of the sale of shares) to the fair market value of the information is timely furnished to the Internal Revenue Service. 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. GeoPark 20F 167 However, the seller may opt to be taxed as if the underlying Chilean Assets had been sold directly in which case a different set of tax rules may apply. H. Documents on display We are subject to the informational requirements of the Exchange Act. Accordingly, we are required to file reports and other information with the SEC, The tax is payable by the seller of the shares; however, the buyer shall make including annual reports on Form 20-F and reports on Form 6-K. You may a provisional withholding unless the seller declares and pays the tax within inspect and copy reports and other information filed with the SEC at the Public the month following the sale, payment, remittance or it is credited into Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on its account or is put at its disposal. Also, if the seller fails to declare and pay the operation of the Public Reference Room may be obtained by calling the this tax, and the buyer has not complied with its withholding obligations, the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website that Chilean tax authority (Servicio de Impuestos Internos) may charge such tax contains reports and other information about issuers, like us, that file directly to any of them. In addition, the Chilean tax authority may require us, electronically with the SEC. The address of that website is www.sec.gov. the seller, the buyer, or its representative in Chile, to file an affidavit with the information necessary to assess this tax. Based on information available to us, (i) no Chilean resident holds 5% or more of our rights to equity, control or profits; or (ii) residents in black-listed jurisdictions I. Subsidiary information Not applicable. hold 50% or more of our rights to equity, control or profits. Therefore, we do not ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES believe the indirect transfer rules will apply to transfers of our common shares, ABOUT MARKET RISK unless the shares or rights transferred represent 10% or more of the company and the other conditions described above are met (considering dispositions by related We are exposed to a variety of market risks, including commodity price risk, persons and over the preceding 12-month period). interest rate risk, currency risk and credit (counterparty and customer) risk. However, there can be no assurance that, at any time in the future, a Chilean changes in interest rates, oil and natural gas prices and foreign currency The term “market risk” refers to the risk of loss arising from adverse resident will not hold 5% or more of our rights to equity, control or profits or exchange rates. that residents in black-listed jurisdictions will not hold 50% or more of our rights to equity, control or profits. If this were to occur, all sales of our common For further information on our market risks, please see Note 3 to our audited shares would be subject to the indirect transfer tax referred to above. consolidated financial statements. Our expectations regarding the indirect transfer rules are based on our understandings, analysis and interpretation of these enacted indirect transfer ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES rules, which are subject to additional interpretation and rule-making by the Chilean authorities. As such, there is uncertainty relating to the application by Chilean authorities of the indirect transfer rules on us. A. Debt securities Not applicable. See “Item 3. Key Information—D. Risk Factors—Risks related to our common shares—The transfer of our common shares may be subject to capital gains B. Warrants and rights Not applicable. taxes pursuant to recently-enacted indirect transfer rules in Chile.” C. Other securities Not applicable. D. American Depositary Shares Not applicable. F. Dividends and paying agents Not applicable. G. Statement by experts Not applicable. 168 GeoPark 20F Part II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES A. Defaults No matters to report. B. Arrears and delinquencies No matters to report. D. Changes in Internal Control over Financial Reporting There was no change in our internal control over financial reporting that occurred during the period covered by this annual report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. ITEM 16. [RESERVED] ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY ITEM 16A. Audit committee financial expert HOLDERS AND USE OF PROCEEDS Not applicable. ITEM 15. CONTROLS AND PROCEDURES We have determined that Mr. Peter Ryalls and Mr. Juan Cristóbal Pavez are independent, as such term is defined under SEC rules applicable to foreign private issuers. In accordance with NYSE rules, we expect to have a fully independent audit committee within one year of listing. In addition, Mr. Steve Quamme and Mr. Juan Cristobal Pavez are regarded as audit A. Disclosure Controls and Procedures As of December 31, 2013, under the supervision and with the participation committee financial experts. of our management, including our Chief Executive Officer and Chief Financial ITEM 16B. Code of Conduct Officer, we performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule We have adopted a code of conduct applicable to the board of directors 13a-15(e) under the Exchange Act). There are inherent limitations to and all employees. Since its effective date on September 24, 2012, we have the effectiveness of any disclosure controls and procedures system, including not waived compliance with or amended the code of conduct. the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable ITEM 16C. Principal Accountant Fees and Services assurance of achieving their control objectives. Amounts billed by Price Waterhouse & Co. S.R.L. for audit and other services Based on such evaluation, our Chief Executive Officer and Chief Financial were as follows: Officer concluded that our disclosure controls and procedures are effective to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (2) accumulated and Audit fees Audit-related fees communicated to our management to allow timely decisions regarding Tax fees required disclosures. Other fees paid Total 2013 2012 (In US$ millions) 0.81 0.03 0.26 0.33 1.43 0.40 0.59 0.12 0.30 1.41 B. Management’s Annual Report on Internal Control over Financial Reporting This annual report does not include a report of management's assessment Audit Fees Audit fees are fees billed for professional services rendered by the principal regarding internal control over financial reporting due to a transition period accountant for the audit of the registrant’s annual financial statements established by rules of the Securities and Exchange Commission for newly or services that are normally provided by the accountant in connection with public companies, or an attestation report of the company’s registered public statutory and regulatory filings or engagements for those fiscal years. accounting firm. It includes the audit of our annual consolidated financial statements and other services that generally only the independent accountant reasonably C. Attestation Report of the Registered Public Accounting Firm Not applicable. can provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission. GeoPark 20F 169 Audit-Related Fees Audit-related fees are fees billed for assurance and related services that ITEM 16D. Exemptions from the listing standards for audit committees are reasonably related to the performance of the audit or review of our Under NYSE and SEC rules for listed companies, we must comply with Rule consolidated financial statements for fiscal years 2013 and 2012 and 10A-3 under the Securities Exchange Act (Listing Standards Relating to not reported under the previous category. These services would include, Audit Committees). Rule 10A-3 provides that we should establish an audit among others: accounting consultations and audits in connection with committee composed of members of the board of directors, meet the acquisitions, internal control reviews, attest services that are not required by requirements specified in the listing standards, or appoint and establish a statue or regulation and consultation concerning financial accounting and board of auditors or similar body to perform the role of the audit committee, in reliance on the general exemption of audit committees of foreign private issuers set forth in Rule 10A-3(c)(3) of the Securities Exchange Act. We have determined that Mr. Peter Ryalls and Mr. Juan Cristóbal Pavez are independent, as such term is defined under SEC rules applicable to foreign private issuers. In accordance with NYSE rules, we expect to have a fully independent audit committee within one year of listing. reporting standards. Tax Fees Tax fees are fees billed for professional services for tax compliance, tax advice and tax planning. Pre-Approval Policies and Procedures Following the listing of our common shares on the NYSE, the Audit Committee proposes the appointment of the independent auditor to the Board to be put to shareholders for approval at the Annual General meeting. The committee oversees the auditor selection process for new auditors and ensures key partners in the appointed firm are rotated in accordance with best practices. Also, following our NYSE listing, the Audit Committee is required to pre-approve the audit and non-audit fees and services performed by the Company’s auditors in order to assure that the provision of such services does not impair the audit firm’s independence. All of the audit fees, audit-related fees and tax fees described in this item 16C have been approved by the Audit Committee. 170 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 2013. Total number of common shares Maximum number (or approximate dollar value) purchased as part of common shares Total number Average price of publicly that may yet of common shares paid per common announced plans be purchased under purchased share in GPB or programs — — — — — — — — — — 50,000 — 50,000 — — — — — — — — — — 5.41 — 5.41 — — — — — — — — — — — — — the plans or programs — — — — — — — — — — — — — 2013 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) Purchased pursuant to the Purchase Program for the account of 303A.11 of the NYSE Listed Company Manual, a brief, general summary of the EBT. See “Item 6. Directors, Senior Management and Employees—B. those differences is provided as follows. Compensation—Share Repurchase Program” for a description. ITEM 16F. Change in registrant’s certifying accountant Not applicable. ITEM 16G. Corporate governance Director independence The NYSE Standards require a majority of the membership of NYSE-listed company boards to be composed of independent directors. Neither Bermuda law, the law of our country of incorporation, nor our memorandum of association or bye-laws require a majority of our board to consist of independent directors. Our common shares are listed on the New York Stock Exchange, 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 Non-management directors’ executive sessions The NYSE Standards require non-management directors of NYSE-listed issuer, we may follow our home country’s corporate governance practices in companies to meet at regularly scheduled executive sessions without lieu of most of the NYSE Standards. Our corporate governance practices management. Our memorandum of association and bye-laws do not require differ in certain significant respects from those that U.S. companies must our non-management directors to hold such meetings. adopt in order to maintain NYSE listing and, in accordance with Section GeoPark 20F 171 Committee member composition The NYSE Standards require domestic NYSE-listed domestic companies Foreign private issuers such as us are exempt from these additional requirements if home country practice is followed. Bermuda law does not to have a nominating/corporate governance committee and a compensation impose similar requirements, and consequently, our audit committee committee that are composed entirely of independent directors. Bermuda does not perform these additional functions. law, the law of our country of incorporation, does not impose similar requirements. 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 and compensation committees prepare a written charter that addresses either purposes and responsibilities or performance evaluations in a manner that the board of directors of a domestic listed company consider two factors that would satisfy the NYSE’s requirements; acquire shareholder approval (in addition to the existing general independence tests) in the evaluation of equity compensation plans in certain cases; or adopt and make publicly of the independence of compensation committee members: (i) the source of available corporate governance guidelines. compensation of the director, including any consulting, advisory or other compensatory fees paid by the listed company, and (ii) whether the director We are incorporated under, and are governed by, the laws of Bermuda. has an affiliate relationship with the listed company, a subsidiary of the listed For a summary of some of the differences between provisions of Bermuda company or an affiliate of a subsidiary of the listed company. In addition, law applicable to us and the laws applicable to companies incorporated before selecting or receiving advice from a compensation consultant or other in Delaware and their shareholders, see “Item 10. Additional Information—B. adviser, the compensation committee of a listed company will be required to Memorandum of association and byelaws.” take into consideration six specific factors, as well as all other factors relevant to an adviser’s independence. Compliance with the compensation committee member independence standards will be required by the earlier of a listed company’s first annual meeting after January 15, 2014 or October 31, 2014. ITEM 16H. Mine safety disclosure Not applicable. Foreign private issuers such as us will be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar requirements, so we will not be required to implement the new NYSE listing standards relating to compensation committees of domestic listed companies. Most of the members of our remuneration committee are independent, and the charter of our remuneration committee does not require the remuneration committee to consider the independence of any advisers that assist them in fulfilling their duties. Additional audit committee functions The NYSE standards require that audit committees of domestic companies to serve a number of functions in addition to reviewing and approving the company’s financial statements, engaging auditors and assessing their independence, and obtaining the legal and other professional advice of experts when necessary. For instance, the NYSE Standards require that the audit committee meet independently with management in a separate session in order to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review a report by the independent auditors describing the firm’s internal quality-control procedures and any issues raised by these procedures. Finally, audit committees are responsible for designing and implementing an internal audit function that assesses the company’s risk management processes and systems of internal control on an ongoing basis. 172 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 page 178. to Exhibit 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on Exhibit no. Description 1.1 Certificate of Incorporation (incorporated herein by reference September 9, 2013). 1.2 Memorandum of Association (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 1.3 Current bye-laws (incorporated herein by reference to Exhibit 3.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 1.4 Form of amended and restated bye-laws (incorporated herein by reference to Exhibit 3.4 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 2.2 Indenture, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Limited, GeoPark Latin America Limited and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.2 to the Company’s Registration Statement on Form F-1 (File No. 333- 191068) filed with the SEC on September 9, 2013). 2.3 Share Pledge Agreement, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Chile S.A., GeoPark Colombia S.A. and Deutsche Bank Trust Company Americas (incorporated herein by reference to Exhibit 4.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). 2.4 Intercompany Loan Pledge Agreement, dated February 11, 2013, among GeoPark Chile Limited Agencia en Chile, GeoPark Fell SpA., 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 173 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 enChile, GeoPark Colombia S.A. and GeoPark Holdings (ENAP) and Cordex Petroleums Inc. (incorporated herein Limited (incorporated herein by reference to Exhibit 10.8 by reference to Exhibit 10.1 to the Company’s Registration to 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 for LG International Corporation, GeoPark Chile Limited Agencia and exploitation of hydrocarbons in the La Cuerva Block, dated en Chile and GeoPark Colombia S.A. (incorporated herein April 16, 2008, between the Colombian Agencia Nacional de by reference to Exhibit 10.9 to the Company’s Registration Hidrocarburos and Hupecol Caracara LLC (incorporated herein Statement on Form F-1 (File No. 333-191068) filed with by reference to Exhibit 10.l2 to the Company’s Registration the SEC on September 9, 2013). Statement on Form F-1 (File No. 333-191068) filed with the SEC 4.10 Subordinated Loan Agreement, dated December 18, 2012, on September 9, 2013). between LG International Corporation and Winchester 4.3 Exploration and Production Contract regarding exploration for Oil & Gas S.A. (incorporated herein by reference to Exhibit and exploitation of hydrocarbons in the Llanos 34 Block, dated 10.10 to the Company’s Registration Statement on Form F-1 March 13, 2009, between the Colombian Agencia Nacional (File No. 333-191068) filed with the SEC on September 9, 2013). de Hidrocarburos and Unión Temporal Llanos 34 (incorporated 4.11 Subscription Agreement, dated October 18, 2011, among LG herein by reference to Exhibit 10.3 to the Company’s International Corporation and GeoPark TdF S.A. (incorporated Registration Statement on Form F-1 (File No. 333-191068) filed herein by reference to Exhibit 10.11 to the Company’s with the SEC on September 9, 2013). Registration Statement on Form F-1 (File No. 333-191068) 4.4 Subscription and Shareholders Agreement, dated February 7, filed with the SEC on September 9, 2013). 2006, among the International Finance Corporation, 4.12 Shareholders’ Agreement, dated October 4, 2011, among LG GeoPark Holdings Limited, Gerald O’Shaughnessy and International Corporation, GeoPark TdF S.A. and GeoPark James F. Park (incorporated herein by reference to Exhibit 10.4 Chile S.A. (incorporated herein by reference to Exhibit 10.12 to the 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, between 4.13 Quota Purchase Agreement, dated May 14, 2013, 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 the e Producão de Petróleo e Gás Ltda (incorporated herein 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 LG SEC on September 9, 2013). International Corporation, GeoPark Chile Limited Agencia en 4.14 Purchase and Sale Agreement for Crude Oil and Condensate Chile, GeoPark Chile S.A. and GeoPark Holdings Limited of Fell Block between Empresa Nacional del Petróleo (ENAP) and (incorporated herein by reference to Exhibit 10.6 to the GeoPark Fell SpA (incorporated herein by reference to Exhibit Company’s Registration Statement on Form F-1 (File No. 333 10.14 to the Company’s Registration Statement on Form F-1 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 LG 4.15 Purchase and Sale Agreement for Natural Gas between International Corporation, GeoPark Chile Limited Agencia GeoPark Chile Limited, Agencia en Chile and Methanex Chile S.A. en Chile and GeoPark Chile S.A. (incorporated herein (incorporated herein by reference to Exhibit 10.15 to the by reference to Exhibit 10.7 to the Company’s Registration Company’s Registration Statement on Form F-1/A (File No. 333 Statement on Form F-1 (File No. 333-191068) filed with 191068) filed with the SEC on October 10, 2013).† the SEC on September 9, 2013). 174 GeoPark 20F Exhibit no. Description 4.16 First Addendum and Amendment to Purchase and Sale Exhibit no. Description 13.2 Certification pursuant to 18 U.S.C. section 1350, as adopted Agreement for Natural Gas between GeoPark Chile Limited, pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* Agencia en Chile and Methanex Chile S.A. (incorporated herein 99.1 Reserves Report of DeGolyer and MacNaughton for reserves in by reference to Exhibit 10.16 to the Company’s Registration Brazil, Chile, Colombia and Argentina as of December 31, 2013.** Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).† * Filed with this Annual Report on Form 20-F. 4.17 Second Addendum and Amendment to Purchase and Sale ** This information can be found in our 20-F filing to the SEC on April 30, 2014 Agreement for Natural Gas between GeoPark Chile Limited, at www.sec.gov or at www.geo-park.com Agencia en Chile and Methanex Chile S.A. (incorporated herein † Confidential treatment of certain provisions of these exhibits has been by reference to Exhibit 10.7 to the Company’s Registration requested with the SEC. Omitted material for which confidential treatment Statement on Form F-1/A (File No. 333-191068) filed with the has been requested has been filed separately with the SEC. SEC on September 26, 2013). 4.18 Third 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 10.18 to the Company’s Registration Statement on Form F-1/A (File No. 333-191068) filed with the SEC on October 10, 2013).† 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 Itau BBA International plc and GeoPark Brasil Exploracão e Produção de Petróleo e Gás Ltda.** 8.1 Subsidiaries of GeoPark Limited (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 February 6, 2014).** 12.1 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* 12.2 Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* 13.1 Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* GeoPark 20F 175 Glossary of Oil and Natural Gas Terms The terms defined in this section are used throughout this annual report: Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well as those items are defined below. “appraisal well” means a well drilled to further confirm and evaluate the “field” means an area consisting of a single reservoir or multiple reservoirs all presence of hydrocarbons in a reservoir that has been discovered. grouped on or related to the same individual geological structural feature “API” means the American Petroleum Institute’s inverted scale for denoting and/or stratigraphic condition. There may be two or more reservoirs in a field the “light” or “heaviness” of crude oils and other liquid hydrocarbons. that are separated vertically by intervening impervious strata, or laterally by “bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used local geologic barriers, or by both. herein in reference to crude oil, condensate or natural gas liquids. Reservoirs that are associated by being in overlapping or adjacent fields “bcf” means one billion cubic feet of natural gas. may be treated as a single or common operational field. The geological terms “boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas structural feature and stratigraphic condition are intended to identify being equivalent to one barrel of oil. localized geological features as opposed to the broader terms of basins, “boepd” means barrels of oil equivalent per day. trends, provinces, plays, areas-of-interest, etc. “bopd” means barrels of oil per day. “formation” means a layer of rock which has distinct characteristics that differ “British thermal unit” or “btu” means the heat required to raise the from nearby rock. temperature of a one-pound mass of water from 58.5 to 59.5 degrees “mbbl” means one thousand barrels of crude oil, condensate or natural gas Fahrenheit. liquids. “basin” means a large natural depression on the earth’s surface in which “mboe” means one thousand barrels of oil equivalent. sediments generally brought by water accumulate. “mcf” means one thousand cubic feet of natural gas. “CEOP” (Contrato Especial de Operación) means a special operating contract “Measurements” include: the Chilean signs with a company or a consortium of companies for the • “m” or “meter” means one meter, which equals approximately 3.28084 feet; exploration and exploitation of hydrocarbon wells. • “km” means one kilometer, which equals approximately 0.621371 miles; “completion” means the process of treating a drilled well followed by the • “sq. km” means one square kilometer, which equals approximately 247.1 installation of permanent equipment for the production of natural gas or oil, acres; or in the case of a dry hole, the reporting of abandonment to the • “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent appropriate agency. to approximately 0.15898 cubic meters; “developed acreage” means the number of acres that are allocated or • “boe” means one barrel of oil equivalent, which equals approximately assignable to productive wells or wells capable of production. 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of “developed reserves” are expected quantities to be recovered from natural gas to one barrel of oil; existing wells and facilities. Reserves are considered developed only after • “cf” means one cubic foot; the necessary equipment has been installed or when the costs to do so • “m,” when used before bbl, boe or cf, means one thousand 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. • “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, respectively; “development well” means a well drilled within the proved area of an oil or • “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, gas reservoir to the depth of a stratigraphic horizon known to be productive. respectively; and “dry hole” means a well found to be incapable of producing hydrocarbons • “pd” means per day. in sufficient quantities such that proceeds from the sale of such production “metric ton” or “MT” means one thousand kilograms. Assuming standard exceed production expenses and taxes. quality oil, one metric ton equals 7.9 bbl. “E&P Contract” means exploration and production contract. “mmbbl” means one million barrels of crude oil, condensate or natural gas “economic interest” means an indirect participation interest in the net liquids. revenues from a given block based on bilateral agreements with the “mmboe” means one million barrels of oil equivalent. concessionaires. “mmbtu” means one million British thermal units. “economically producible” means a resource that generates revenue that “NYMEX” means The New York Mercantile Exchange. exceeds, or is reasonably expected to exceed, the costs of the operation. “net acres” means the percentage of total acres an owner has out of a “exploratory well” means a well drilled to find and produce oil or gas in an particular number of acres, or a specified tract. An owner who has a 50% unproved area, to find a new reservoir in a field previously found to be interest in 100 acres owns 50 net acres. productive of oil or gas in another reservoir, or to extend a known reservoir. “productive well” means a well that is found to be capable of producing 176 GeoPark 20F hydrocarbons in sufficient quantities such that proceeds from the sale of the rock types and thus has the potential to become rich hydrocarbon source production exceed production expenses and taxes. rock. Its fine grain size and lack of permeability can allow shale to form a good “prospect” means a potential trap which may contain hydrocarbons and is cap rock for hydrocarbon traps. supported by the necessary amount and quality of geologic and geophysical “spacing” means the distance between wells producing from the same data to indicate a probability of oil and/or natural gas accumulation ready reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing, to be drilled. The five required elements (generation, migration, reservoir, seal and is often established by regulatory agencies). and trap) must be present for a prospect to work and if any of them fail “spud” means the very beginning of drilling operations of a new well, neither oil nor natural gas will be present, at least not in commercial volumes. occurring when the drilling bit penetrates the surface utilizing a drilling rig “proved developed reserves” means those proved reserves that can be capable of drilling the well to the authorized total depth. expected to be recovered through existing wells and facilities and by existing “stratigraphic test well” means a drilling effort, geologically directed, to operating methods. obtain information pertaining to a specific geologic condition. Such wells “proved reserves” means estimated quantities of crude oil, natural gas, and customarily are drilled without the intention of being completed for natural gas liquids which geological and engineering data demonstrate with hydrocarbon production. This classification also includes tests identified reasonable certainty to be economically recoverable in future years from as core tests and all types of expendable holes related to hydrocarbon known reservoirs under existing economic and operating conditions, as well exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not 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. recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2). “undeveloped reserves” are quantities expected to be recovered through “proved undeveloped reserves” means are those proved reserves that future investments: (1) from new wells on undrilled acreage in known are expected to be recovered from future wells and facilities, including future accumulation, (2) from deepening existing wells to a different (but known) improved recovery projects which are anticipated with a high degree of reservoir, (3) from infill wells that will increase recover, or (4) where a certainty in reservoirs which have previously shown favorable response to relatively large expenditure (e.g., when compared to the cost of drilling a new improved recovery projects. well) is required to (a) recomplete an existing well or (b) install production “reasonable certainty” means a high degree of confidence. or transportation facilities for primary or improved recovery projects. “recompletion” means the process of re-entering an existing wellbore that is “unit” means the joining of all or substantially all interests in a reservoir or either producing or not producing and completing new reservoirs in an field, rather than a single tract, to provide for development and operation attempt to establish or increase existing production. without regard to separate property interests. Also, the area covered “reserves” means estimated remaining quantities of oil and gas and related by a unitization agreement. substances anticipated to be economically producible, as of a given date, “wellbore” means the hole drilled by the bit that is equipped for oil or gas by application of development projects to known accumulations. In addition, production on a completed well. Also called well or borehole. there must exist, or there must be a reasonable expectation that there will “working interest” means the right granted to the lessee of a property to exist, a revenue interest in the production, installed means of delivering oil, explore for and to produce and own oil, gas, or other minerals. The working gas, or related substances to market, and all permits and financing required to implement the project. interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis. “reservoir” means a porous and permeable underground formation “workover” means operations in a producing well to restore or increase containing a natural accumulation of producible oil and/or gas that production. 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 GeoPark 20F 177 Index to Consolidated Financial Statements Audited Annual Consolidated Financial Statements—GeoPark Limited Report of Independent Registered Public Accounting Firm 180 Consolidated Statements of Income and Comprehensive Income for the Fiscal Years Ended December 31, 2013, 2012 and 2011 Consolidated Statement of Financial Position as of December 31, 2013 and 2012 Consolidated Statements of Changes in Equity for the Fiscal Years Ended December 31, 2013, 2012 and 2011 Consolidated Statements of Cash Flows for the Fiscal Years Ended December 31, 2013, 2012 and 2011 Notes to the Audited Annual Consolidated Financial Statements for the Fiscal Years Ended December 31, 2013 and 2012 181 182 183 184 185 178 GeoPark 20F GeoPark 20F 179 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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 April 29, 2014 180 GeoPark 20F Consolidated Statement of Income Amounts in US$ ’000 Note 2013 2012 2011 7 8 11 12 13 14 15 34 16 Net Revenue Production costs Gross Profit Exploration costs Administrative costs Selling expenses Other operating income Operating Profit Financial income Financial expenses 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$) for profit attributable to owners of the Company. Basic 18 Earnings per share (in US$) for profit attributable to owners of the Company. Diluted 18 338,353 (179,643) 158,710 250,478 (129,235) 121,243 (16,254) (46,584) (17,252) 5,344 83,964 4,893 (38,769) — 50,088 (15,154) 34,934 22,012 12,922 0.50 0.47 (27,890) (28,798) (24,631) 823 40,747 892 (17,200) 8,401 32,840 (14,394) 18,446 11,879 6,567 0.28 0.27 111,580 (54,513) 57,067 (10,066) (18,232) (2,546) (439) 25,784 162 (13,678) — 12,268 (7,206) 5,062 54 5,008 0.00 0.00 Consolidated Statement of Comprehensive Income Amounts in US$ ’000 2013 2012 2011 Income for the year Other comprehensive income: Items that may be subsequently reclassified to profit Currency translation difference Total comprehensive Income for year Attributable to: Owners of the Company Non-controlling interest 34,934 18,446 5,062 (1,956) 32,978 — 18,446 20,056 12,922 11,879 6,567 — 5,062 54 5,008 The notes on pages 185 to 228 are an integral part of these consolidated financial statements. GeoPark 20F 181 Consolidated Statement of Financial Position Amounts in US$ ’000 Note 2013 2012 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 28 595,446 457,837 11,454 5,168 13,358 6,361 10,707 7,791 13,591 510 631,787 490,436 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 3,955 32,271 49,620 3,443 48,292 137,581 628,017 43 116,817 128,421 (5,860) 239,421 72,665 312,086 290,457 165,046 33,076 23,087 8,344 25,991 17,502 — 354,964 208,539 26,630 7,231 91,633 125,494 480,458 846,415 27,986 7,315 72,091 107,392 315,931 628,017 The financial statements were approved by the Board of Directors on 28 March 2014. The notes on pages 185 to 228 are an integral part of these consolidated financial statements. 182 GeoPark 20F Consolidated Statement of Changes in Equity Attributable to owners of the Company Retained earnings Non- Other Translation (accumulated controlling Reserve 3,025 Reserve 894 losses) (19,527) Interest — Total 92,292 Share Capital(1) 42 — — — 1 1 43 — — — — — 43 — — — — 1 — 1 44 Amount in US$ '000 Equity at 1 January 2011 Comprehensive income: Profit for the year Total Comprehensive Income for the Year 2011 Transactions with owners: Proceeds from transaction with Non-controlling interest (Notes 25 and 34) Share-based payment (Note 29) Total 2011 Balances at 31December 2011 Comprehensive income: Profit for the year Total Comprehensive Income for the Year 2012 Transactions with owners: Proceeds from transaction with Noncontrolling interest (Notes 25 and 34) Share-based payment (Note 29) Total 2012 Balances at 31December 2012 Comprehensive income: Profit for the year Currency translation differences Total Comprehensive Income for the Year 2013 Transactions with owners: Proceeds from transaction with Noncontrolling interest (Notes 25 and 34) Share-based payment (Note 29) Repurchase of shares (Note 25) Total 2013 Balances at 31 December 2013 (1) See Note 1. Share Premium 107,858 — — — — — 111,245 4,373 4,373 112,231 — 111,245 114,270 — — — — — 4,586 4,586 116,817 13,257 — 13,257 127,527 — — — — 4,049 (440) 3,609 — — — — — — — 120,426 127,527 (1,062) The notes on pages 185 to 228 are an integral part of these consolidated financial statements. 54 54 5,008 5,062 5,008 5,062 — 36,755 148,000 924 924 — 36,755 41,763 5,298 153,298 250,652 894 (18,549) 11,879 6,567 18,446 11,879 6,567 18,446 — 810 810 894 (5,860) — (1,956) 22,012 — 24,335 — 24,335 72,665 12,922 — 37,592 5,396 42,988 312,086 34,934 (1,956) (1,956) 22,012 12,922 32,978 — — — — — — — — — — — — — — — 7,754 — 7,754 23,906 9,529 — — 9,529 95,116 9,529 11,804 (440) 20,893 365,957 GeoPark 20F 183 Consolidated Statement of Cash Flow Amounts in US$ ’000 Note 2013 2012 2011 Cash flows from operating activities Income for the year Adjustments for: Income tax for the year Depreciation of the year Loss on disposal of property, plant and equipment Write-off of unsuccessful efforts Impairment loss 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 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 Purchase of financial assets Collections related to financial leases 16 9 11 27 27 10 34 27 5 34 24 34,934 18,446 5,062 15,154 70,200 575 10,962 — 22,085 (1,165) 1,523 9,167 — — (4,040) (19,301) 140,094 (228,033) — — 6,734 14,394 53,317 546 25,552 — 12,513 (2,143) 1,262 5,396 (8,401) 5,550 (408) 5,778 7,206 26,408 2,010 5,919 1,344 11,115 (1,038) 350 5,298 — 5,000 — 89 131,802 68,763 (198,204) (105,303) — — (98,651) — (2,625) — Cash flows used in investing activities – net (221,299) (303,507) (101,276) 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 Interest paid Cash flows from financing activities - net 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 9,668 142,000 — — — (9,150) (10,779) 131,739 Net increase (decrease) in cash and cash equivalents 82,813 (145,330) 99,226 Cash and cash equivalents at 1 January Cash and cash equivalents at the end of the year 38,292 121,105 183,622 38,292 84,396 183,622 Ending Cash and cash equivalents are specified as follows: Cash in bank Cash in hand Bank overdrafts Cash and cash equivalents 121,113 22 (30) 121,105 48,268 24 (10,000) 38,292 193,642 8 (10,028) 183,622 (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. The notes on pages 185 to 228 are an integral part of these consolidated financial statements. 184 GeoPark 20F Notes Note 1 General Information On 7 February 2014, the Securities and Exchange Commission (“SEC”) declared effective the Company’s registration statement upon which 13,999,700 shares were issued at a price of US$7 per share, including over- GeoPark Limited (the Company) is a company incorporated under the laws allotment option. Gross proceeds from the offering totalled US$98 million. of Bermuda. The Registered office address is Cumberland House, 9th Floor, As a result, the Company commenced trading on the New York Stock 1 Victoria Street, Hamilton HM 11, Bermuda. Exchange (“NYSE”) under the ticker symbol GPRK. Also its shares On 30 July 2013 the shareholders approved the change of the Company’s name from GeoPark Holdings Limited to GeoPark Limited. Subsequently, the Company listing cancellation on the AIM London Stock are authorized for trading on the Santiago Off-Shore Stock Exchange. The principal activity of the Company and its subsidiaries (“the Group”) are exploration, development and production for oil and gas reserves in Chile, These consolidated financial statements were authorised for issue by the Colombia, Brazil and Argentina. The Group has working interests and/or Board of Directors on 28 March 2014. Exchange became effective on 19 February 2014. economic interests in 28 hydrocarbon blocks. The Group was founded in 2002. The first acquisition was the purchase of Note 2 AES Corporation’s upstream oil and natural gas assets in Chile and Argentina. Summary of significant accounting policies Those assets included a non-operating working interest in the Fell Block in Chile, which at that time was operated by Empresa Nacional de Petróleo The principal accounting policies applied in the preparation of these (“ENAP”), the Chilean state-owned hydrocarbon company, and operating consolidated financial statements are set out below. These policies have been working interests in the Del Mosquito, Cerro Doña Juana and Loma Cortaderal consistently applied to the years presented, unless otherwise stated. blocks in Argentina. In 2006, the Group was awarded a 100% operating working interest in the Fell Block by the Republic of Chile. In 2008 and 2009, the Group continued the growth in Chile by acquiring operating working 2.1 Basis of preparation The consolidated financial statements of GeoPark Limited have been interests in each of the Otway and Tranquilo blocks. In 2011, the Group was prepared in accordance with International Financial Reporting Standards awarded operating working interests in each of the Isla Norte, Flamenco (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). and Campanario blocks in Tierra del Fuego, Chile, and in 2012, the Group formalized and entered into special operation contracts (Contratos The consolidated financial statements are presented in thousands (US$ ’000) Especiales de Operación para la Exploración y Explotación de Yacimientos of United States Dollars and all values are rounded to the nearest thousand de Hidrocarburos) (each, a “CEOP”) with Chile for the exploitation and (US$’000), except where otherwise indicated. exploration of these blocks. In the first quarter of 2012, GeoPark extended its footprint to Colombia by acquiring three privately held Exploration and Production (“E&P”) companies, Winchester, La Luna and Cuerva, that includes The consolidated financial statements have been prepared on a historical cost basis. working interests and/or economic interests in 10 blocks located in the Llanos, Magdalena and Catatumbo basins. 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 seven new licenses in the Brazilian Round 11 of which two policies. The areas involving a higher degree of judgement or complexity, are in the Reconcavo Basin in the State of Bahia and five are in the Potiguar or areas where assumptions and estimates are significant to the consolidated Basin in the State of Rio Grande do Norte. In addition, in November 2013, financial statements are disclosed in this note under the title “Accounting the Company has also been awarded two new concessions in a new estimates and assumptions”. international bidding round, Round 12, in the Parnaíba Basin in the State of Maranhão and Sergipe Alagoas Basin in the State of Alagoas (see Note 34). GeoPark 20F 185 2.1.1 Changes in accounting policy and disclosure New standards, amendments and interpretations issued but not effective for the New and amended standards adopted by the Group financial year beginning 1 January 2013 and not early adopted IFRS 9, ‘Financial instruments’, addresses the classification, measurement The following standards have been adopted by the Group for the first and recognition of financial assets and financial liabilities. IFRS 9 was issued time for the financial year beginning on or after 1 January 2013 and have in November 2009 and October 2010. It replaces the parts of IAS 39 that no material impact on the Group: relate to the classification and measurement of financial instruments. IFRS 9 requires financial assets to be classified into two measurement categories: Amendment to IAS 1, ‘Financial statement presentation’ regarding other those measured at fair value and those measured at amortised cost. The comprehensive income. The main change resulting from these amendments determination is made at initial recognition. The classification depends is a requirement for entities to group items presented in ‘other on the entity’s business model for managing its financial instruments and comprehensive income’ (OCI) on the basis of whether they are potentially the contractual cash flow characteristics of the instrument. For financial reclassifiable to profit or loss subsequently (reclassification adjustments). liabilities, the standard retains most of the IAS 39 requirements. IFRS 10, ‘Consolidated financial statements’ builds on existing principles The main change is that, in cases where the fair value option is taken for by identifying the concept of control as the determining factor in whether an financial liabilities, the part of a fair value change due to an entity’s own credit entity should be included within the consolidated financial statements of risk is recorded in other comprehensive income rather than the income the parent company. The standard provides additional guidance to assist in statement, unless this creates an accounting mismatch. The Group is yet to the determination of control where this is difficult to assess. assess IFRS 9’s full impact and intends to adopt IFRS 9 no later than the accounting period beginning on or after 1 January 2015. IFRS 11, ‘Joint arrangements’ focuses on the rights and obligations of the parties to the arrangement rather than its legal form. There are two types Amendment to IAS 32, ‘Financial instruments: Presentation’ on asset and of joint arrangements: joint operations and joint ventures. Joint operations liability offsetting. These amendments are to the application guidance in arise where the investors have rights to the assets and obligations for IAS 32, ‘Financial instruments: Presentation’, and clarify some of the the liabilities of an arrangement. A joint operator accounts for its share of requirements for offsetting financial assets and financial liabilities on the the assets, liabilities, revenue and expenses. Joint ventures arise where balance sheet. The Company has assessed IAS 32’s impact and concluded the investors have rights to the net assets of the arrangement; joint ventures there will be no material impact on the Group. are accounted for under the equity method. Proportional consolidation of joint arrangements is no longer permitted. Amendment to IAS 36, ‘Impairment of assets’ on recoverable amount IFRS 12, ‘Disclosures of interests in other entities’ includes the disclosure the recoverable amount of impaired assets if that amount is based on fair requirements for all forms of interests in other entities, including joint arrangements, associates, structured entities and other off balance sheet value less costs of disposal. The Company has assessed IAS 36’s impact and concluded there will be no material impact on the Group. disclosures. This amendment addresses the disclosure of information about vehicles. IFRIC 21, ‘Levies’, is an interpretation of IAS 37, ‘Provisions, contingent IFRS 13, ‘Fair value measurement’, aims to improve consistency and reduce liabilities and contingent assets’. IAS 37 sets out criteria for the recognition of complexity by providing a precise definition of fair value and a single source a liability, one of which is the requirement for the entity to have a present of fair value measurement and disclosure requirements for use across IFRSs. obligation as a result of a past event (known as an obligating event). The The requirements, which are largely aligned between IFRSs and US GAAP, interpretation clarifies that the obligating event that gives rise to a liability to do not extend the use of fair value accounting but provide guidance on how pay a levy is the activity described in the relevant legislation that triggers the it should be applied where its use is already required or permitted by other payment of the levy. The Company has assessed IFRIC 21’s impact and standards within IFRSs. concluded there will be no material impact on the Group. 186 GeoPark 20F There are no other IFRSs or IFRIC interpretations that are not yet effective that Acquisition-related costs are expensed as incurred. would be expected to have a material impact on the Group. Management assessed the relevance of other new standards, amendments controlling interest in the acquiree and the acquisition-date fair value of or interpretations not yet effective and concluded that they are not relevant any previous equity interest in the acquiree over the fair value of the The excess of the consideration transferred, the amount of any non- to Group. identifiable net assets acquired is recorded as goodwill. If the total of consideration transferred, noncontrolling interest recognized and previously 2.2 Going concern The Directors regularly monitor the Group's cash position and liquidity risks held interest measured is less than the fair value of the net assets of the subsidiary acquired in the case of a bargain purchase, the difference is throughout the year to ensure that it has sufficient funds to meet forecast recognized directly in the income statement. operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other Intercompany transactions, balances and unrealised gains on transactions factors to enable the Group to manage the risk of any funding short falls between the Group and its subsidiaries are eliminated. Unrealised and/or potential loan covenant breaches. losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial Considering macroeconomic environment conditions, the performance of statements of subsidiaries have been adjusted where necessary to ensure the operations, the US$300 million debt fund raising completed in February consistency with the accounting policies adopted by the Group. 2013, the proceeds from the registration statement with the SEC (see Note 1) and Group’s cash position, the Directors have formed a judgement, at the time of approving the financial statements, that there is a reasonable 2.4 Segment reporting Operating segments are reported in a manner consistent with the internal expectation that the Group has adequate resources to continue with reporting provided to the chief operating decision-maker. The chief its investment programme to increase oil and gas reserves, production and operating decision-maker, who is responsible for allocating resources and revenues and meeting all its obligations for the foreseeable future. For assessing performance of the operating segments, has been identified this reason, the Directors have continued to adopt the going concern basis as the strategic steering committee that makes strategic decisions. This in preparing the consolidated financial statements. committee consists of the CEO, COO, CFO and managers in charge of the Exploration, Development, Drilling, Operations, SPEED and Finance 2.3 Consolidation Subsidiaries are all entities (including structured entities) over which the departments. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has group has control. The group controls an entity when the group is exposed determined the operating segments based on these reports. to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. 2.5 Foreign currency translation Subsidiaries are fully consolidated from the date on which control is transferred to the group. They are deconsolidated from the date that control ceases. The Group applies the acquisition method to account for business a) Functional and presentation currency The consolidated financial statements are presented in US Dollars, which is the Group’s presentation currency. combinations. The consideration transferred for the acquisition of a subsidiary Items included in the financial statements of each of the Group’s entities are is the fair values of the assets transferred, the liabilities incurred to the measured using the currency of the primary economic environment in former owners of the acquiree and the equity interests issued by the Group. which the entity operates (the “functional currency”). The functional currency The consideration transferred includes the fair value of any asset or liability of Group companies incorporated in Chile, Colombia and Argentina is resulting from a contingent consideration arrangement. Identifiable assets the US Dollar, meanwhile for the Group Brazilian company the functional acquired and liabilities and contingent liabilities assumed in a business currency is the local currency, which is the Brazilian Real. combination are measured initially at their fair values at the acquisition date. GeoPark 20F 187 b) Transactions and balances Foreign currency transactions are translated into the functional currency 2.10 Property, plant and equipment Property, plant and equipment are stated at historical cost less depreciation, using the exchange rates prevailing at the dates of the transactions. Foreign and impairment if applicable. Historical cost includes expenditure that is exchange gains and losses resulting from the settlement of such transactions directly attributable to the acquisition of the items; including provisions for and from the translation at period end exchange rates of monetary assets asset retirement obligation. and liabilities denominated in foreign currencies are recognised in the Consolidated Statement of Income. 2.6 Joint arrangements The company has applied IFRS 11 to all joint arrangements as of 1 January Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing 2013. Under IFRS 11 investments in joint arrangements are classified as either exploration and evaluation costs until such time as the economic viability joint operations or joint ventures depending on the contractual rights and of producing the underlying resources is determined. Costs incurred prior to obligations each investor. obtaining legal rights to explore are expensed immediately to the Consolidated Statement of Income. The Company has assessed the nature of its joint arrangements and determined them to be joint operations. The company combines its share in Exploration and evaluation costs may include: license acquisition, geological the joint operations individual assets, liabilities, results and cash flows on a and geophysical studies (i.e.: seismic), direct labour costs and drilling line-by-line basis with similar items in its financial statements. costs of exploratory wells. No depreciation and/or amortisation are charged 2.7 Revenue recognition Revenue from the sale of crude oil and gas is recognised in the Statement during the exploration and evaluation phase. Upon completion 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 of Income when risk transferred to the purchaser, and if the revenue the determination is made depending whether they have found reserves can be measured reliably and is expected to be received. Revenue is shown or not. If not developed, exploration and evaluation assets are written net of VAT, discounts related to the sale and overriding royalties due to off after three years unless, it can be clearly demonstrated that the carrying the ex-owners of oil and gas properties where the royalty arrangements value of the investment is recoverable. represent a retained working interest in the property. 2.8 Production costs Production costs include wages and salaries incurred to achieve the Statement of Income within Exploration costs (US$25,552,000 in 2012 and US$5,919,000 in 2011) for write-offs in Argentina, Colombia and Chile net revenue for the year. Direct and indirect costs of raw materials (see Note 11). A charge of US$10,962,000 has been recognised in the Consolidated and consumables, rentals and leasing, property, plant and equipment depreciation and royalties are also included within this account. All field development costs are considered construction in progress until they are finished and capitalised within oil and gas properties, and are subject 2.9 Financial costs Financial costs include interest expenses, realised and unrealised gains and to depreciation once complete. Such costs may include the acquisition and installation of production facilities, development drilling costs (including dry losses arising from transactions in foreign currencies and the amortisation holes, service wells and seismic surveys for development purposes), project- of financial assets and liabilities. The Company has capitalised borrowing cost related engineering and the acquisition costs of rights and concessions for wells and facilities that were initiated after 1 January 2009. Amounts related to approved properties. capitalised during the year totalled US$1,312,953 (US$1,368,952 in 2012 and US$597,127 in 2011). Work overs of wells made to develop reserves and/or increase production are capitalized as development costs. Maintenance costs are charged to income when incurred. 188 GeoPark 20F Capitalised costs of proved oil and gas properties and production facilities changes in technology and the variations in the costs of restoration necessary and machinery are depreciated on a licensed area by the licensed area basis, to protect the environment, the Group has considered it appropriate to using the unit of production method, based on commercial proved and periodically re-evaluate future costs of well-capping. The effects of this probable reserves. The calculation of the “unit of production” depreciation recalculation are included in the financial statements in the period in which takes into account estimated future finding and development costs and is this recalculation is determined and reflected as an adjustment to the based on current year end unescalated price levels. Changes in reserves provision and the corresponding property, plant and equipment asset. and cost estimates are recognised prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. 2.11.2 Deferred Income Relates to contributions received in cash from the Group’s clients to improve Depreciation of the remaining property, plant and equipment assets (i.e. the project economics of gas wells. The amounts collected are reflected furniture and vehicles) not directly associated with oil and gas activities has as a deferred income in the balance sheet and recognised in the Consolidated been calculated by means of the straight line method by applying such Statement of Income over the productive life of the associated wells. The annual rates as required to write-off their value at the end of their estimated depreciation of the gas wells that generated the deferred income is charged useful lives. The useful lives range between 3 years and 10 years. to the Consolidated Statement of Income simultaneously with the Depreciation is allocated in the Consolidated Statement of Income as production, exploration and administrative expenses, based on the nature of the associated asset. amortisation of the deferred income. 2.12 Impairment of non-financial assets Assets that are not subject to depreciation and/or amortisation (i.e.: exploration and evaluation assets) are tested annually for impairment. An asset’s carrying amount is written down immediately to its recoverable Assets that are subject to depreciation and/or amortisation are reviewed amount if the asset’s carrying amount is greater than its estimated for impairment whenever events or changes in circumstances indicate that recoverable amount (see Impairment of non-financial assets in Note 2.12). the carrying amount may not be recoverable. 2.11 Provisions and other long-term liabilities Provisions for asset retirement obligations, deferred income, restructuring An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is obligations and legal claims are recognised when the Group has a present the higher of an asset’s fair value less costs to sell and value in use. For the legal or constructive obligation as a result of past events; it is probable purposes of assessing impairment, assets are grouped at the lowest levels for that an outflow of resources will be required to settle the obligation; and which there are separately identifiable cash flows (cash-generating units), the amount has been reliably estimated. Restructuring provisions comprise generally a licensed area. Non-financial assets other than goodwill that lease termination penalties and employee termination payments. suffered impairment are reviewed for possible reversal of the impairment at each reporting date. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current No asset should be kept as an exploration and evaluation asset for a period market assessments of the time value of money and the risks specific to the of more than three years, except if it can be clearly demonstrated that the obligation. The increase in the provision due to passage of time is recognised carrying value of the investment will be recoverable. as interest expense. 2.11.1 Asset Retirement Obligation The Group records the fair value of the liability for asset retirement No impairment loss has been recognised during 2013; only write-offs (see Note 11). In 2011, a charge of US$1,344,000 was recognised within exploration costs as a result of the impairment test performed regarding obligations in the period in which the wells are drilled. When the liability operating fields in Argentina (see Note 11). is initially recorded, the Group capitalises the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and application of current legislation and on the basis of the GeoPark 20F 189 2.13 Lease contracts All current lease contracts are considered to be operating leases on the In addition, the Group has tax-loss carry-forwards in certain taxing jurisdictions that are available to offset against future taxable profit. However, basis that the lessor retains substantially all the risks and rewards related to deferred tax assets are recognized only to the extent that it is probable the ownership of the leased asset. Payments related to operating leases that taxable profit will be available against which the unused tax losses can and other rental agreements are recognised in the Consolidated Income be utilized. Management judgment is exercised in assessing whether this Statement on a straight line basis over the term of the contract. The Group's is the case. total commitment relating to operating leases and rental agreements is disclosed in Note 31. To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. Leases in which substantially all of the risks and rewards of ownership are transferred to the lessee are classified as finance leases. Under a finance lease, Deferred income tax liabilities are provided on taxable temporary the Company as lessor has to recognize an amount receivable equal to the differences arising from investments in subsidiaries and joint arrangements, aggregate of the minimum lease payments plus any unguaranteed residual except for deferred income tax liability where the timing of the reversal of the value accruing to the lessor, discounted at the interest rate implicit in the lease. temporary difference is controlled by the Group and it is probable that the 2.14 Inventories Inventories comprise crude oil and materials. temporary difference will not reverse in the foreseeable future. The Group is able to control the timing of dividends from its subsidiaries and hence does not expect taxable profit. Hence deferred tax is recognized in respect of the retained earnings of overseas subsidiaries only if at the date of the statements Crude oil is measured at the lower of cost and net realisable value. Materials of financial position, dividends have been accrued as receivable or a binding are measured at the lower of cost and recoverable amount. The cost of agreement to distribute past earnings in future has been entered into by materials and consumables is calculated at acquisition price with the addition the subsidiary. of transportation and similar costs. Cost is determined using the first-in, firstout (FIFO) method. Deferred tax liabilities are provided in full, with no discounting. 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 recognised in the Consolidated Statement of Income. receivables; financial assets at fair value through the profit or loss; available- for-sale financial assets; and held-to-maturity investments. Financial assets The current income tax charge is calculated on the basis of the tax laws are assigned to the different categories by management on initial enacted or substantially enacted at the balance sheet date in the countries recognition, depending on the purpose for which the investments were where the Company’s subsidiaries operate and generate taxable income. acquired. The designation of financial assets is re-evaluated at every reporting The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution date at which a choice of classification or accounting treatment is available. of tax positions taken by the Group, through negotiations with relevant tax All financial assets are recognised when the Group becomes a party to the authorities or through litigation, can take several years to complete and contractual provisions of the instrument. All financial assets are initially in some cases it is difficult to predict the ultimate outcome. recognised at fair value, plus transaction costs. Deferred income tax is recognised, using the liability method, on temporary Derecognition of financial assets occurs when the rights to receive cash differences arising between the tax bases of assets and liabilities and their flows from the investments expire or are transferred and substantially all of carrying amounts in the consolidated financial statements. Deferred income the risks and rewards of ownership have been transferred. An assessment tax is determined using tax rates (and laws) that have been enacted or for impairment is undertaken at each balance sheet date. substantially enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income Interest and other cash flows resulting from holding financial assets are tax liability is settled. recognised in the Consolidated Income Statement when receivable, regardless of how the related carrying amount of financial assets is measured. 190 GeoPark 20F Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are 2.21 Borrowings Borrowings are obligations to pay cash and are recognised when the Group included in current assets, except for maturities greater than twelve months becomes a party to the contractual provisions of the instrument. after the balance sheet date. These are classified as non-current assets. The Group’s loans and receivables comprise trade receivables, prepayments Borrowings are recognised initially at fair value, net of transaction costs and other receivables and cash at bank and in hand in the balance sheet. incurred. Borrowings are subsequently stated at amortised cost; They arise when the Group provides money, goods or services directly to a any difference between the proceeds (net of transaction costs) and the debtor with no intention of trading the receivables. Loans and receivables are redemption value is recognised in the Consolidated Statement of Income subsequently measured at amortised cost using the effective interest over the period of the borrowings using the effective interest method. method, less provision for impairment. Any change in their value through impairment or reversal of impairment is recognised in the Consolidated Direct issue costs are charged to the Consolidated Statement of Income Statement of Income. All of the Group’s financial assets are classified as loan on an accruals basis using the effective interest method. and receivables. 2.17 Other financial assets Non-current other financial assets include contributions made for 2.22 Share capital Equity comprises the following: • "Share capital" representing the nominal value of equity shares. environmental obligations according to a Colombian government request. • "Share premium" representing the excess over nominal value of the fair For 2012, noncurrent other financial assets also relate to the cash collateral value of consideration received for equity shares, net of expenses of the account required under the terms of the Bond issued in 2010. This investment share issue. was intended to guarantee interest payments and was recovered at • "Other reserve" representing: repayment date (see Note 26). - the equity element attributable to shares granted according to IFRS 2 but not issued at year end or, 2.18 Impairment of financial assets Provision against trade receivables is made when objective evidence is - the difference between the proceeds from the transaction with non- controlling interests received against the book value of the shares acquired received that the Group will not be able to collect all amounts due to in the subsidiaries GeoPark Chile S.A. and GeoPark Colombia S.A. it in accordance with the original terms of those receivables. The amount (see Note 34). of the write-down is determined as the difference between the asset's • "Translation reserve" representing the differences arising from translation carrying amount and the present value of estimated future cash flows. of investments in overseas subsidiaries. • "Retained earnings (accumulated losses)" representing accumulated 2.19 Cash and cash equivalents Cash and cash equivalents includes cash in hand, deposits held at call with earnings and losses. banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts, if any, are shown 2.23 Share-based payment The Group operates a number of equity-settled and cash-settled share-based within borrowings in the current liabilities section of the Consolidated compensation plans comprising share awards payments and stock options Statement of Financial Position. plans to certain employees and other third party contractors. 2.20 Trade and other payables Trade payables are obligations to pay for goods or services that have been Share-based payment transactions are measured in accordance with IFRS 2. acquired in the ordinary course of the business from suppliers. Accounts Fair value of the stock option plan for employee or contractors services payable are classified as current liabilities if payment is due within one year received in exchange for the grant of the options is recognised as an expense. or less (or in the normal operating cycle of the business if longer). If not, The total amount to be expensed over the vesting period is determined by they are presented as non-current liabilities. reference to the fair value of the options granted calculated using the Black- Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. Scholes model. GeoPark 20F 191 Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. At each balance sheet date, Currency risk In Argentina, Colombia and Chile the functional currency is the US Dollar. the entity revises its estimates of the number of options that are expected The fluctuation of the local currencies of these countries against the US Dollar to vest. It recognises the impact of the revision to original estimates, does not impact the loans, costs and revenues held in US Dollars; but it if any, in the Consolidated Statement of Income, with a corresponding does impact the balances denominated in local currencies. Such is the case adjustment to equity. of the prepaid taxes. The fair value of the share awards payments is determined at the grant date In Chile, Colombia and Argentina subsidiaries most of the balances are by reference of the market value of the shares and recognised as an expense denominated in US Dollars, and since it is the functional currency of the over the vesting period. subsidiaries, there is no exposure to currency fluctuation except from receivables or payables originated in local currency mainly corresponding When the options are exercised, the Company issues new shares. The to VAT. The balances as of 31 December 2013 of VAT were credits for proceeds received net of any directly attributable transaction costs US$3,177,000 (US$3,624,000 in 2012) in Argentina, credits for US$5,288,000 are credited to share capital (nominal value) and share premium when (US$221,000 in 2012) in Chile and VAT payable for US$5,870,000 the options are exercised. (US$2,418,000 in 2012) in Colombia. For cash-settled share-based payment transactions, the Company measures The Group minimises the local currency positions in Argentina, Colombia and the services acquired for amounts that are based on the price of the Chile by seeking to equilibrate local and foreign currency assets and liabilities. Company’s shares. The fair value of the liability incurred is measured using However, tax receivables (VAT) are very difficult to match with local currency Geometric Brownian Motion method. Until the liability is settled, the liabilities. Therefore the Group maintains a net exposure to them. Company is required to re-measure the fair value of the liability at each reporting date and at the date of settlement, with any changes in value Most of the Group's assets held in those countries are associated with oil recognized in profit or loss for the period. and gas productive assets. Such assets in the oil and gas industry even in the Note 3 Financial Instruments-risk management local markets are usually settled in US Dollar equivalents. During 2013, the Argentine Peso weakened by 33% (weakened by 16% and 8% in 2012 and 2011 respectively) against the US Dollar, the Chilean Peso weakened by 10% (strengthened by 8% in 2012 and weakened by 11% The Group is exposed through its operations to the following financial risks: in 2011) and the Colombian Peso weakened by 9% (strengthened by 9% • Currency risk • Price risk • Credit risk – concentration • Funding and liquidity risk • Interest rate risk • Capital risk management in 2012). If the Argentine Peso, the Chilean Peso and the Colombian Peso had each weakened an additional 5% against the US dollar, with all other variables held constant, post-tax profit for the year would have been higher by US$139,500 (lower by US$45,500 in 2012 and by US$41,000 in 2011 respectively). During 2014, the Argentine Peso weakened by approximately 22% against The policy for managing these risks is set by the Board. Certain risks are the US Dollar. The Company estimates that this devaluation will not impact managed centrally, while others are managed locally following guidelines significantly the results of the Company. communicated from the corporate office. The policy for each of the above risks is described in more detail below. 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. Most of the balances are denominated in Brazilian Real, and since it is the 192 GeoPark 20F functional currency of the Brazilian subsidiary, there is no exposure to currency fluctuation except from cash at bank held in US Dollars. Credit risk – concentration The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognised values. There is not considered to be any During 2013, the Brazilian Real weakened by 6% against the US Dollar. If the significant risk in respect of the Group’s major customers. Brazilian Real had weakened an additional 5% against the US dollar, with all other variables held constant, post-tax profit for the year would have been In Chile, most of gas production is sold to the local subsidiary of the higher by US$1,826,000. Methanex Corporation, a Canadian public company (7% of total revenue, 12% in 2012 and 34% in 2011). All the oil produced in Chile is sold to ENAP As currency rate changes between the U.S. Dollar and the local currencies, the (40% of total revenue, 48% in 2012 and 65% in 2011), the State owned Group recognizes gains and losses in the Consolidated Statement of Income. oil and gas company. In Colombia, 21% of the oil we produced there, was sold to Hocol, a subsidiary of Ecopetrol, the Colombian Sate owned oil Price risk The price realised for the oil produced by the Group is linked to WTI (West Company (11% of total revenue, 31% in 2012). The mentioned companies all have good credit standing and despite the concentration of the credit risk, Texas Intermediate) and Brent, which is settled in the international markets in the Directors do not consider there to be a significant collection risk. US dollars. The market price of these commodities is subject to significant fluctuation but the Board does not consider it appropriate to manage the See disclosure in Note 24. Group’s risk to such fluctuation through futures contracts or similar because to do so would not have been efficiently economic at the achieved production levels. Funding and Liquidity risk The Group has strong support from its financial partners and maintains flexibility in adjusting the programme to ensure the development of the key In Chile, the oil price is based on WTI minus certain marketing and quality properties. discounts such as, inter alia, API quality and mercury content; the price formula also includes adjustments for differences between the WTI and Brent During 2012, LGI made a capital subscription in GeoPark Colombia S.A. for an at certain price levels. In Argentina, the oil price is also subject to the impact amount of US$14,920,000 for the 20% of the Colombian business. In addition, of the retention tax on oil exports defined by the Argentine government as part of the transaction, US$5,000,000 was transferred directly to the which limits the direct correlation to the WTI. Colombian subsidiary as a loan (see Note 34). The Company has signed a long-term Gas Supply Contract with Methanex in In addition, during 2013 the Company placed US$300 million notes (see Note Chile. The price of the gas under this contract is indexed to the international 26) and on February 2014 collected US$98 million from the registration methanol price. statement with the SEC (see Note 1). If the market prices of WTI, Brent and methanol had fallen by 10% compared to actual prices during the year, with all other variables held constant, Interest rate risk The Group’s profit and operating cash flows are substantially independent post-tax profit for the year would have been lower by US$27,179,000 of changes in market interest rates. The Group’s interest rate risk arises from (US$18,784,000 in 2012 and US$9,501,000 in 2011). long-term borrowings issued at variable rates, which expose the Group to The Board will consider adopting a hedging policy against commodity price risk, when deemed appropriate, according to the size of the business and The Group does not face interest rate risk on its US$300,000,000 Notes market implied volatility. which carry a fixed rate coupon of 7.50% per annum. cash flow to interest rate risk. The Group analyses its interest rate exposure on a dynamic basis. Various scenarios are simulated taking into consideration refinancing, renewal of existing positions, alternative financing and hedging. Based on these scenarios, the Group calculates the impact on profit and loss of a defined interest rate shift. For each simulation, the same interest rate shift is used for all currencies. The scenarios are run only for liabilities that represent the major interest-bearing positions. GeoPark 20F 193 At 31 December 2012, if interest rates on currency-denominated borrowings Note 4 had been 1% higher with all other variables held constant, post-tax profit Accounting estimates and assumptions for the year would have been US$160,866 lower (US$144,267 in 2011). At 31 December 2013, the Group has no exposure to fluctuations in the Although these estimates are based on management's best knowledge of interest rate, since its long-term borrowings were issued at fixed rate. current events and actions, actual results may differ from them. Estimates and Estimates and assumptions are used in preparing the financial statements. Capital risk management The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. shareholders and benefits for other stakeholders and to maintain an optimal The key estimates and assumptions used in these consolidated financial capital structure to reduce the cost of capital. statements are noted below: Consistent with others in the industry, the Group monitors capital on the • The Group adopts the successful efforts method of accounting. The basis of the gearing ratio. This ratio is calculated as net debt divided by total Management of the Company makes assessments and estimates regarding capital. Net debt is calculated as total borrowings (including ‘current and whether an exploration asset should continue to be carried forward as an non-current borrowings’ as shown in the consolidated balance sheet) less exploration and evaluation asset not yet determined or when insufficient cash at bank and in hand. Total capital is calculated as ‘equity’ as shown information exists for this type of cost to remain as an asset. In making this in the consolidated balance sheet plus net debt. assessment the Management takes professional advice from qualified experts. The Group’s strategy is to keep the gearing ratio within a 30% to 45% range. • Cash flow estimates for impairment assessments require assumptions about two primary elements - future prices and reserves. Estimates of future Particularly, in 2011 the gearing ratio has been affected by the transactions prices require significant judgments about highly uncertain future events. with non-controlling interests, by which the Group received proceeds of Historically, oil and gas prices have exhibited significant volatility. Our US$142,000,000. forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and our own assessments. The gearing ratios at 31 December 2013 and 2012 were as follows: Our estimates of future cash flows are generally based on our assumptions Amounts in US$ ’000 Net Debt Total Equity Total Capital Gearing Ratio 2013 (a)265,952 365,957 631,909 42% of long-term prices and operating and development costs. 2012 144,740 Given the significant assumptions required and the possibility that actual 312,086 conditions will differ, we consider the assessment of impairment to be a 456,826 32% critical accounting estimate. The process of estimating reserves is complex. It requires significant (a) For the calculation of the gearing ratio the Group does not consider the judgements and decisions based on available geological, geophysical, cash that has been allocated for future M&A activities. In 2013, the Group has engineering and economic data. The estimation of economically recoverable allocated US$70 million for the acquisition of Río Das Contas (see Note 34). oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report dated December 2013 prepared by DeGolyer and MacNaughton, an international consultancy to the oil and gas industry based in Dallas. It incorporates many factors and assumptions including: - expected reservoir characteristics based on geological, geophysical and engineering assessments; - future production rates based on historical performance and expected future operating and investment activities; - future oil and gas prices and quality differentials; 194 GeoPark 20F - assumed effects of regulation by governmental agencies; and Amounts in US$ ’000 - future development and operating costs. Increase in asset retirement obligation Transactions with Management believes these factors and assumptions are reasonable based non-controlling interests on the information available to us at the time we prepare our estimates. Financial leases (Note 19) However, these estimates may change substantially as additional data from 2013 7,183 — 14,133 2012 3,440 — — 2011 1,948 6,000 — ongoing development activities and production performance becomes Cash flows from investing activities include payments in connection with available and as economic conditions impacting oil and gas prices and costs the purchase and sale of property, plant and equipment, cash flows relating change. to the purchase and sale of enterprises to third parties and cash flows from financial lease transactions. Cash flows from financing activities include • Oil and gas assets held in property plant and equipment are mainly changes in Shareholders’ equity, and proceeds from borrowings and depreciated on a unit of production basis at a rate calculated by reference to repayment of loans. Cash and cash equivalents include bank overdraft and proven and probable reserves and incorporating the estimated future cost liquid funds with a term of less than three months. of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce Changes in working capital shown in the Consolidated Statement of Cash those reserves, the cost of the wells and future production facilities. Flow are disclosed as follows: • Obligations related to the plugging of wells once operations are terminated Amounts in US$ ’000 may result in the recognition of significant obligations. Estimating the Change in Prepaid taxes future abandonment costs is difficult and requires management to make Change in Inventories estimates and judgments because most of the obligations are many Change in Trade receivables years in the future. Technologies and costs are constantly changing as well Change in Prepayments and other as political, environmental, safety and public relations considerations. receivables and Other assets The Company has adopted the following criterion for recognising well Change in liabilities plugging and abandonment related costs: The present value of future costs necessary 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 Company’s indebtedness. The liabilities recognised Note 6 are based upon estimated future abandonment costs, wells subject to Segment information abandonment, time to abandonment, and future inflation rates. 2013 (4,283) (4,166) (10,357) (13,330) 12,835 (19,301) 2012 (11,046) 8,837 (7,842) 2011 892 (332) (2,858) 9,759 6,070 5,778 (16,350) 18,737 89 Note 5 Management has determined the operating segments based on the reports reviewed by the strategic steering committee that are used to make strategic decisions. The committee considers the business from a geographic Consolidated Statement of Cash Flow perspective. The Consolidated Statement of Cash Flow shows the Group's cash flows The strategic steering committee assesses the performance of the operating for the year for operating, investing and financing activities and the change segments based on a measure of adjusted earnings before interest, tax, in cash and cash equivalents during the year. depreciation, amortisation and certain non-cash items such as write-offs, impairments and share-based payments (Adjusted EBITDA). This Cash flows from operating activities are computed from the results for the measurement basis excludes the effects of non-recurring expenditure from year adjusted for non-cash operating items, changes in net working the operating segments, such as impairments when it is the result of an capital, and corporation tax. Tax paid is presented as a separate item under isolated, non-recurring event. Interest income and expenses are not included operating activities. in the result for each operating segment that is reviewed by the strategic steering committee. Other information provided, except as noted below, to The following chart describes non-cash transactions related to the the strategic steering committee is measured in a manner consistent with Consolidated Statement of Cash Flow: that in the financial statements. GeoPark 20F 195 Segment areas (geographical segments): Amount in US$ ’000 Argentina Brazil Colombia Chile Corporate Total 2013 Net revenue Gross profit Operating (loss) / profit Adjusted EBITDA Depreciation Impairment and write-off Total assets Employees (average) 2012 Net revenue Gross profit Operating (loss) / profit Adjusted EBITDA Depreciation Impairment and write-off Total assets Employees (average) 2011 Net revenue Gross profit Operating (loss) / profit Adjusted EBITDA Depreciation Impairment and write-off Total assets Employees (average) 1,538 1,192 (1,942) 166 (225) — 7,977 97 1,050 (2,194) (6,129) 2,051 (3,408) (1,915) 6,108 100 1,477 179 (5,973) (1,081) (1,083) (1,344) 10,895 83 — — (3,107) (3,037) (2) — 29,222 3 — — — — — — — — — — — — — — — — 179,324 67,612 38,811 82,611 (39,406) (3,258) 259,421 107 99,501 39,304 8,500 34,474 (21,050) (5,147) 213,202 80 — — — — — — — — 157,491 89,906 63,110 96,348 (30,471) (7,704) 477,263 184 149,927 84,133 47,915 93,908 (28,734) (18,490) 405,674 144 110,103 56,888 39,425 70,421 (25,297) (5,919) (1)453,384 98 — — (12,908) (8,835) (96) — 72,532 — — — (9,539) (9,029) (125) — 3,033 — — — (7,668) (5,949) (28) — 7,990 1 338,353 158,710 83,964 167,253 (70,200) (10,962) 846,415 391 250,478 121,243 40,747 121,404 (53,317) (25,552) 628,017 324 111,580 57,067 25,784 63,391 (26,408) (7,263) 472,269 182 (1) Includes cash received from disposal of 20% of the Chilean business in 2011. Approximately 63% of capital expenditure was allocated to Chile (70% in 2012 and 95% in 2011) and 37% was allocated to Colombia (30% in 2012 and 0% in 2011). 196 GeoPark 20F A reconciliation of total Adjusted EBITDA to total profit before income tax Note 9 is provided as follows: Amounts in US$ ’000 Adjusted EBITDA for reportable segments Depreciation Share-based payment Impairment and write-off of unsuccessful efforts Others(a) Operating profit Financial results Bargain purchase gain on acquisition of subsidiaries Profit before tax Depreciation 2013 2012 2011 Amounts in US$ ’000 Oil and gas properties 167,253 (70,200) (9,167) 121,404 (53,317) (5,396) 63,391 (26,408) Production facilities and machinery Furniture, equipment and vehicles (5,298) Buildings and improvements (10,962) 7,040 83,964 (33,876) (25,552) 3,608 40,747 (16,308) (7,263) 1,362 25,784 (13,516) Depreciation of property, plant and equipment Recognised as follows: Production costs Administrative costs — 50,088 8,401 32,840 — Depreciation total 12,268 2013 59,234 9,341 964 661 2012 44,552 7,708 713 344 2011 20,096 5,767 343 202 70,200 53,317 26,408 68,579 1,621 70,200 52,307 1,010 53,317 25,844 564 26,408 (a) Includes internally capitalised costs. Note 10 Staff costs and Directors Remuneration Note 7 Net Revenue Amounts in US$ ’000 Sale of crude oil Sale of gas Note 8 Production costs Amounts in US$ ’000 Depreciation Well and facilities maintenance Royalties Consumables Staff costs (Note 10) 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 2013 315,435 22,918 2012 221,564 28,914 Average number of employees Amounts in US$ ’000 2011 Wages and salaries 73,508 38,072 Share-based payment (Note 29) Share-based payment – Cash awards 338,353 250,478 111,580 Social security charges Board of Directors’ and key managers’ remuneration Salaries and fees Share-based payment Other benefits 2013 68,579 20,662 17,239 14,855 14,202 11,392 7,139 5,635 4,843 4,805 3,217 — 7,075 2012 52,307 9,385 11,424 9,884 14,171 7,211 5,936 1,030 1,428 2,407 3,371 3,826 6,855 179,643 129,235 2011 25,844 5,080 4,843 1,687 6,015 2,541 — — 316 1,009 3,242 — 3,936 54,513 2013 391 29,504 8,362 805 5,291 43,962 7,702 2,971 742 11,415 2012 324 19,132 5,396 — 3,636 28,164 5,711 846 — 6,557 2011 182 9,914 5,298 — 2,228 17,440 4,045 2,257 — 6,302 GeoPark 20F 197 Directors’ Remuneration Gerald O’Shaughnessy James F. Park Pedro Aylwin1 Sir Michael Jenkins2 Peter Ryalls Christian Weyer3 Juan Cristóbal Pavez4 Carlos Gulisano Steven J. Quamme Executive Directors’ Executive Directors’ Non-Executive Director Fees Paid in Cash Equivalent Total 2013 Cash Payment Stock Payment Fees US$250,000 US$500,000 Bonus US$150,000 US$300,000 — — — — — — — — — — — — — — Directors’ Fees Shares No. of Shares Remuneration — — — £5,813 £17,500 £18,678 £23,250 £37,875 £20,375 — — — 1,712 2,906 — 2,906 — 2,906 US$400,000 US$800,000 — US$27,234 US$55,414 US$29,697 US$64,484 US$59,902 US$59,902 1 Pedro Aylwin has a service contract that provides for him to act as Manager of Legal and Governance. 2 Audit Committee Chairman until his death on 31 March 2013. Afterwards the Chairman is Steven J. Quamme. 3 Nomination Committee Chairman until his resignation on 15 April 2013. Afterwards the Chairman is Carlos Gulisano. 4 Remuneration Committee Chairman. Name Stock Awards to Executive Directors The following Stock Options were issued to Executive Directors during 2012: N° of Underlying Common Shares Grant Date 23 Nov 2012 23 Nov 2012 Exercise Price (US$) 0.001 0.001 Earliest Exercise Date 23 Nov 2015 23 Nov 2015 Non-executive director fee includes a fee of £5,750 for holding a committee Gerald O’Shaughnessy 270,000 chairman position during the year. James F. Park 450,000 IPO Stock Options to Executive Directors The following Stock Options were issued to Executive Directors during 2006: Name N° of Underlying Common Shares 153,345 Gerald O’Shaughnessy 306,690 153,345 James F. Park 306,690 Exercise Price (£) 3.20 4.00 3.20 4.00 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: Earliest Exercise Date 15 May 2008 Expiry Date • 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 15 May fully exercised during 2013. 2013 • 100,000 Stock awards issued on 15 December 2008 at an exercise price of 15 May 15 May $0.001 to be exercised between 15 December 2012 and 15 December 2018. 2008 15 May 2008 15 May 2008 2013 15 May 2013 15 May 2013 During 2013 the abovementioned stock options were fully exercised by the Executive Directors. 198 GeoPark 20F Note 11 Exploration costs Amounts in US$ ’000 Write-off of unsuccessful efforts(a) Staff costs (Note 10) Other services Allocation to capitalised project Amortisation of other long-term liabilities related to unsuccessful efforts Impairment loss(b) Recovery of abandonments costs Note 12 Administrative costs 2013 10,962 7,676 1,406 (2,437) (600) — (753) 2012 25,552 4,418 1,269 (1,849) (1,500) — — 2011 5,919 3,277 1,597 Amounts in US$ ’000 Staff costs (Note 10) Consultant fees New projects (1,471) Office expenses Director’s fees and allowance Travel expenses Depreciation Other administrative expenses (600) 1,344 — 16,254 27,890 10,066 (a) The 2013 charge corresponds to the cost of five unsuccessful exploratory Note 13 wells: two of them in Chile (one in Fell Block and one in Tranquilo Block) Selling expenses and three of them in Colombia (one well in Cuerva Block, one well in each of the non-operated blocks, Arrendajo and Llanos 32). The 2012 charge Amounts in US$ ’000 corresponds to the costs of eight unsuccessful exploratory wells: five of them Transportation in Chile (two in Fell Block, two in Otway Block and the remaining in Tranquilo Delivery or pay penalty Block) and three of them in Colombia (one well in Cuerva Block, one well Storage in Arrendajo Block and the remaining in Llanos 17 Block). The 2012 charge Selling taxes also includes the loss generated by the relinquishment of an area in the Del Mosquito Block in Argentina. The 2011 charge corresponds to the write- off of exploration and evaluation assets in the Fell Block. The charge includes the cost of an unsuccessful exploratory well amounting to US$2,331,000 Note 14 and also in accordance with the Group’s accounting policy and considering Financial income that no additional work would be performed, wells from previous years were written-off for an amount of US$3,588,000. Amounts in US$ ’000 (b) The impairment charge relates to assets located in Del Mosquito Block Exchange difference based on the impairment test performed in 2011. Interest received 2013 22,084 6,424 3,720 2,652 1,426 1,258 1,621 7,399 2012 9,575 5,122 2,927 3,293 1,516 1,563 1,010 3,792 46,584 28,798 2011 8,148 1,896 1,726 1,172 903 686 564 3,137 18,232 2013 16,181 — 665 406 2012 22,066 1,718 645 202 2011 1,886 — 508 152 17,252 24,631 2,546 2013 1,468 3,425 4,893 2012 348 544 892 2011 32 130 162 GeoPark 20F 199 Note 15 Financial expenses Amounts in US$ ’000 Bank charges and other financial costs Exchange difference Bond GeoPark Fell SpA cancellation costs (Note 26) Unwinding of long-term liabilities 2013 2,519 2,228 8,603 1,523 2012 1,764 2,429 — 1,262 2011 1,856 496 — 350 Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any 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 and Chile) ranges from 15% to 35%. Interest and amortisation of debt issue costs Less: amounts capitalised on qualifying assets Note 16 Income tax Amounts in US$ ’000 Current tax Deferred income tax (Note 17) 25,209 13,114 11,573 future taxable profit in the following countries: The Group has significant tax losses available which can be utilised against (1,313) 38,769 (1,369) 17,200 (597) Amounts in US$ ’000 13,678 Argentina Total tax losses at 31 December 2013 10,259 10,259 2012 11,645 11,645 2011 18,656 18,656 2013 13,337 1,817 15,154 2012 7,536 6,858 14,394 At the balance sheet date deferred tax assets in respect of tax losses in Argentina have not been recognised as there is insufficient evidence of future taxable profits before the statute of limitation of these tax losses 2011 causes them to expire. 187 7,019 7,206 Expiring dates for tax losses accumulated at 31 December 2013 are: Expiring date Amounts in US$ ’000 477 3,778 1,985 2,617 1,402 2014 2015 2016 2017 2018 The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows: Amounts in US$ ’000 Profit before tax Tax losses from non-taxable jurisdictions Taxable profit 2013 50,088 2012 32,840 2011 12,268 14,348 64,436 8,373 41,213 8,565 20,833 Income tax calculated at domestic tax rates applicable to profits in the respective countries 14,011 6,290 5,473 Tax losses where no deferred income tax is recognised Effect of currency translation on tax base Expiration of tax loss carry-forwards Non-taxable results(1) Income tax 328 2,864 2,560 (5,146) 1,988 3,973 2,436 — 2,804 15,154 14,394 (761) — (66) 7,206 (1) Includes non-deductible expenses in each jurisdiction and changes in the estimation of deferred tax assets and liabilities. 200 GeoPark 20F Note 17 Deferred income tax Note 18 Earnings per share The gross movement on the deferred income tax account is as follows: Amounts in US$ ’000 2013 2012 2011 Amounts in US$ ’000 Deferred tax at 1 January Acquisition of subsidiaries Reclassification(1) Income statement charge Deferred tax at 31 December 2013 (3,911) — (4,001) (1,817) (9,729) 2012 (12,659) 15,606 — (6,858) (3,911) Numerator: 2011 Profit for the year (5,640) Denominator: 22,012 11,879 54 — — Weighted average number of shares used in basic EPS 43,603,846 42,673,981 41,912,685 (7,019) Earnings after tax per (12,659) share (US$) – basic and diluted 0.50 0.28 0.00 The breakdown and movement of deferred tax assets and liabilities as of Amounts in US$ ’000 2013 2012 2011 31 December 2013, 2012 and 2011 are as follows: Weighted average number of shares used in basic EPS 43,603,846 42,673,981 41,912,685 At the Acquisition (Charged) / Effect of dilutive potential Amounts in US$ ’000 of year sidiaries net profit beginning of sub- credited to Deferred tax assets Difference in depreciation rates and other Taxable losses(2) Total 2013 Total 2012 Total 2011 9,211 4,380 13,591 450 374 — — — 15,606 — (11,788) 11,555 (233) (2,465) 76 At end of year (2,577) 15,935 common shares Stock award at US$0.001 2,928,203 1,435,324 2,004,482 Weighted average number of common shares for the purposes of diluted earnings per shares 46,532,049 44,109,305 43,917,167 13,358 Earnings after tax 13,591 per share (US$) – diluted 0.47 0.27 0.00 450 At the (Charged) / beginning credited to Amounts in US$ ’000 of year net profit Reclassi- fication(1) At end of year Deferred tax liabilities Difference in depreciation rates and other Total 2013 Total 2012 Total 2011 (17,502) (17,502) (13,109) (6,014) (1,584) (1,584) (4,393) (7,095) (4,001) (4,001) (23,087) (23,087) — (17,502) — (13,109) (1) Corresponds to the difference between 2012 income tax provision and the final form presented, which resulted in a higher deferred income tax liability and lower income tax payable. (2) In Chile, taxable losses have no expiration date. GeoPark 20F 201 Note 19 Property, plant and equipment Amount in US$ ’000 Cost at 1 January 2011 Additions Disposals Write-off / Impairment Transfers Cost at 31 December 2011 Additions Disposals Write-off / Impairment Acquisition of subsidiaries Transfers Cost at 31 December 2012 Additions Disposals Write-off / Impairment Transfers Cost at 31 December 2013 Depreciation and write-down at 1 January 2011 Depreciation Depreciation and write-down at 31 December 2011 Depreciation Depreciation and write-down at 31 December 2012 Depreciation Depreciation and write-down Furniture, Production Buildings Oil & gas equipment facilities and and Construction in properties and vehicles machinery improvements 126,626 2,318 (227) — 43,239 171,956 4,071 (416) — 62,449 106,311 344,371 9,367 (553) — 140,075 493,260 (33,508) (20,096) (53,604) (44,552) (98,156) (59,234) 1,445 825 (177) — 82 2,175 637 — — 389 375 3,576 2,060 (22) — 117 5,731 (851) (343) (1,123) (713) (1,836) (964) 38,142 1,261 (1,852) — 9,551 47,102 32,335 (130) — 10,865 (3,223) 86,949 512 (*)(15,870) — 27,246 98,837 (13,308) (5,767) (18,628) (7,708) (26,336) (9,341) 2,076 156 — — 205 2,437 — — — — 761 3,198 — — — 3,820 7,018 (514) (202) (716) (344) (1,060) (661) Exploration and evaluation assets(1) 23,412 39,469 — (7,263) (13,478) 42,140 83,360 — (25,552) 27,818 (34,660) 93,106 133,301 — (10,962) (67,686) Total 207,898 100,599 (2,528) (7,263) — 298,706 201,644 (546) (25,552) 110,973 — 585,225 235,216 (16,445) (10,962) — 147,759 793,034 — — — — — — — (48,181) (26,408) (74,071) (53,317) (127,388) (70,200) (197,588) progress 16,197 56,570 (272) — (39,599) 32,896 81,241 — — 9,452 (69,564) 54,025 89,976 — — (103,572) 40,429 — — — — — — — at 31 December 2013 (157,390) (2,800) (35,677) (1,721) 118,352 1,052 28,474 1,721 32,896 42,140 224,635 246,215 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 Carrying amount at 31 December 2011 Carrying amount at 31 December 2012 Carrying amount at 31 December 2013 202 GeoPark 20F As of 31 December 2013, 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$493,000 (US$692,000 in 2012 and US$638,000 in 2011). See Note 26. Exploration wells at 31 December 2010 Additions On 25 August 2011 the exploratory period in the Fell Block ended. The exploration programme carried out during the exploration period enabled the Company to declare commerciality on approximately 84% of the total area of the Block. The remaining area not declared as commercial was relinquished, which did not generate any loss for the Group. (*) During 2013, the Company entered into a finance lease for which it has transferred a substantial portion of the risk and rewards of some assets Write-offs Transfers Exploration wells at 31 December 2011 Additions Write-offs Transfers Acquisition of subsidiaries Exploration wells at 31 December 2012 Additions which had a book value of US$14.1 million. As of 31 December 2013, Write-offs prepayments and other receivables include receivables under finance leases Transfers amounting to US$8.0 million, which US$6.5 million are maturity no later Exploration wells at 31 December 2013 than one year and US$1.5 million between one and five years. Total Total 5,787 35,400 (5,919) (13,027) 22,241 47,891 (21,339) (23,496) 1,868 27,165 77,933 (7,934) (67,246) 29,918 unearned interest income amounts to US$1.2 million. As of 31 December 2013, there were five exploratory wells that have been capitalised for a period over a year amounting to US$11,251,000 (nil in 2012) (1) Exploration wells movement and balances are shown in the below and six exploratory wells that have been capitalised for a period less than a table; seismic and other exploratory assets amount to US$117,841,000 year amounting to US$18,667,000 (US$27,165,000 in 2012). (US$65,941,000 in 2012 and US$39,899,000 in 2011). GeoPark 20F 203 Note 20 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of 31 December 2013: GeoPark Limited (Bermuda) 100% 100% 99.9% 99.9% GeoPark Latin America Limited – Bermuda (Bermuda) 100% GeoPark Latin America Limited Agencia en Chile (Chile) 1% GeoPark Argentina Limited – Bermuda (Bermuda) GeoPark Latin America Coöperatie U.A. (Netherlands) 100% 80% GeoPark Argentina Limited - Argentinean Branch (Argentina) GeoPark Colombia Coöperatie U.A. (Netherlands) 20% LG International GeoPark Brazil Coöperatie U.A. (Netherlands) 99.9% GeoPark Brazil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) 80% 99.9% LG International 20% GeoPark Chile S.A. (Chile) GeoPark S.A. (Chile) 14% 86% 100% 99% GeoPark TdF S.A. (Chile) GeoPark Fell SpA. (Chile) GeoPark Magallanes Limitada (Chile) 100% GeoPark Colombia SAS (Chile) 204 GeoPark 20F Details of the subsidiaries and joint operations of the Company are set out below: Subsidiaries Associates Joint operations Name and registered office GeoPark Argentina Ltd. – Bermuda GeoPark Argentina Ltd. – Argentine Branch GeoPark Latin America GeoPark Latin America – Agencia en Chile GeoPark S.A. (Chile) GeoPark Brazil Exploração y Produção de Petróleo e Gas 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 Cooperatie U.A. (The Netherlands) GeoPark Colombia Cooperatie U.A. (The Netherlands) GeoPark Brazil Cooperatie U.A. (The Netherlands) Raven Pipeline Company LLC (United States) Tranquilo Block (Chile) Otway Block (Chile) Flamenco Block (Chile) Isla Norte Block (Chile) Campanario Block (Chile) Llanos 17 Block (Colombia) Yamu/Carupana Block (Colombia) Llanos 34 Block (Colombia) Llanos 32 Block (Colombia) Ownership interest 100% 100%(a) 100%(h) 100%(a)(h) 100%(a)(b) 100% 80%(a)(c) 80%(a)(c) 80%(a)(c) 68.8%(a)(d) 80%(a)(e) 100%(a)(e)(i) 100%(a)(b) 100%(b) 100%(b) 100%(b) 23.5%(b) 29%(j)(g) 25%(f)(g) 50%(g) 60%(g) 50%(g) 36.84% 75%/54.5%(g) 45%(g) 10% (a) Indirectly owned. (b) Dormant companies. (g) GeoPark is the operator in all blocks. (h) Formerly named GeoPark Chile Limited. (c) LG International has 20% interest. (i) During 2013, the Company has finalized a merger process by which (d) LG International has 20% interest through GeoPark Chile S.A. and a 14% GeoPark Colombia SAS will continue the operations related to GeoPark Luna direct interest, totalling 31.2%. SAS (Colombia), GeoPark Llanos SAS (Colombia), La Luna Oil Co. Ltd. (e) During the first quarter of 2012, the Company entered into a business (Panama), Winchester Oil and Gas S.A. (Panama), GeoPark Cuerva LLC combination acquiring 100% interest in each entity. In December 2012, (United States), Sucursal La Luna Oil Co. Ltd. (Colombia), Sucursal Winchester LG International acquired 20% equity. Oil and Gas S.A. (Colombia) and Sucursal GeoPark Cuerva LLC (Colombia). (f) In April 2013, the Group voluntarily relinquished to the Chilean Government all (j) At 31 December 2013, the Consortium members and interest were: of our acreage in the Otway Block, except for 49,421 acres. In May 2013, our GeoPark 29%, Pluspetrol 29%, Wintershall 25% and Methanex 17%. During partners under the joint operating agreement governing the Otway Block decided 2014, Methanex announced its decision to abandon the Consortium. to withdraw from such joint operating agreement and to apply to withdraw The new ownership will be as follows: GeoPark 37.5%, Pluspetrol 34.9% and from the Otway Block CEOP, such that, subject to the Chilean Ministry of Energy’s Wintershall 27.6%. approval, the Group will be the sole participant, and have a working interest of 100%, in the remaining areas in the Otway Block. GeoPark 20F 205 Note 21 Prepaid taxes Amounts in US$ ’000 V.A.T. Withholding tax Income tax credits Other prepaid taxes Total prepaid taxes Classified as follows: Current Non-current Total prepaid taxes Note 22 Inventories Amounts in US$ ’000 Crude oil Materials and spares Note 23 At 31 December 2013, the Group has no receivables for which exist impairment indicators. Therefore, the Group has no recognised any provision for receivables impairment. 2012 5,962 3,347 4,692 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 149 trade receivables. 2013 10,635 4,601 344 2,853 18,433 14,150 6,979 11,454 18,433 The carrying value of trade receivables is considered to represent a 3,443 reasonable approximation of its fair value due to their short-term nature. 10,707 14,150 Note 24 Financial instruments by category 2013 4,464 3,658 8,122 2012 3,838 117 3,955 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 Loans and receivables 2013 2012 42,628 15,508 5,168 121,135 184,439 32,271 8,773 7,791 48,292 97,127 Trade receivables and Prepayments and other receivables (*) Other financial assets relate to contributions made for environmental obligations according to Colombian government regulations. For 2012, they 2012 also include the cash collateral account required under the terms of the 32,271 Bond issued in 2010. This investment was intended to guarantee interest payments and was recovered at repayment date (see Note 26). 82,401 Amounts in US$ ’000 Liabilities as per statement of financial position Trade payables 81,891 510 To be paid to co-venturers 82,401 Borrowings Other financial liabilities at amortised cost 2013 2012 61,130 1,201 50,590 2,007 317,087 193,032 379,418 245,629 Amounts in US$ ’000 Trade accounts receivable To be recovered from co-venturers Related parties receivables (Note 32) Prepayments and other receivables Total Classified as follows: Current Non-current Total 2013 42,628 42,628 15,508 — 26,617 42,125 84,753 78,392 6,361 84,753 32,271 8,773 31,138 10,219 50,130 Trade receivables that are aged by less than three months are not considered impaired. As of 31 December 2013, trade receivables of US$1,143,393 (US$31,984 in 2012) were aged by more than 3 months, but not impaired. These relate to customers for whom there is no recent history of default. There are no balances due between 31 days and 90 days as of 31 December 2013 and 2012. 206 GeoPark 20F Credit quality of financial assets The credit quality of financial assets that are neither past due nor impaired Financial liabilities - contractual undiscounted cash flows The table below analyses the Group’s financial liabilities into relevant can be assessed by reference to external credit ratings (if available) or to maturity groupings based on the remaining period at the balance sheet to historical information about counterparty default rates: the contractual maturity date. The amounts disclosed in the table are the Amounts in US$ ’000 Trade receivables Counterparties with an external credit rating (Moody’s) Ba1 Baa1 Baa2 Baa3 Counterparties without an external credit rating Group1(*) Total trade receivables 2013 2012 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 — — 2,048 17,321 23,259 42,628 4,769 13,488 At 31 December 2013 Borrowings 4,781 Trade payables — 9,233 At 31 December 2012 Borrowings 32,271 Trade payables 39,585 61,130 22,600 67,500 345,000 — — — 100,715 22,600 67,500 345,000 36,031 50,590 86,621 10,437 181,100 — — 10,437 181,100 — — — (*) Group 1 – existing customers (more than 6 months) with no defaults in the past. All trade receivables are denominated in US Dollars. Cash at bank and other financial assets(1) Amounts in US$ ’000 2013 2012 Counterparties with an external credit rating (Moody’s, Fitch, BRC Investor Services) Note 25 Share capital Issued share capital Common stock (amounts in US$ ’000) The share capital is distributed as follows: 2013 44 2012 43 A1 A3 Aa1 Aa3 P1 P2 P3 AA+ BRC 1+ 4,812 7,408 Common shares, of nominal US$0.001 — — 11 102,390 460 3,789 2,643 3,546 366 Total common shares in issue 2,131 38,952 2,537 — — — — Authorised share capital US$ per share Number of common shares (US$0.001 each) Amount in US$ 43,861,614 43,861,614 43,495,585 43,495,585 0.001 0.001 5,171,949,000 5,171,969,000 5,171,949 5,171,969 Counterparties without an external Details regarding the share capital of the Company are set out below: credit rating Total 8,631 126,282 4,665 56,059 Common shares As of 31 December 2013 the outstanding common shares confer the (1) The rest of the balance sheet item ‘cash at bank and in hand’ is cash on following rights on the holder: hand amounting to US$21,000 (US$24,000 in 2012). • • the right to one vote per share; ranking pari passu, the right to any dividend declared and payable on common shares; GeoPark 20F 207 GeoPark Shares issued Shares closing US$ for the account of the EBT. This Purchase Program expired on 31 December (`000) 2013. The common shares purchased under the program will be used to common shares history Date (millions) (millions) Closing satisfy future awards under the incentive schemes. During 2013, the Company Shares outstanding at the end of 2010 Issue of shares to Non-Executive Directors 2011 May 2011 Oct 2011 Oct 2011 Stock awards Stock awards IPO stock options Shares outstanding at the end of 2011 Issue of shares to Non-Executive Directors 2012 Stock awards Oct 2012 Shares outstanding at the end of 2012 Issue of shares to Non-Executive Directors 2013 Stock awards Sept 2013 Shares outstanding at the end of 2013 41.7 41.7 41.8 41.9 42.5 42.5 42.5 43.5 43.5 43.5 43.9 0.01 0.06 0.10 0.60 0.02 1.01 0.01 0.36 42 42 42 42 43 43 43 43 purchased 50,000 common shares for a total amount of US$440,000. The accounting treatment of the shares is in line with the Group’s policy on share-based payments. Other Reserve During 2011, LGI acquired a 20% interest in GeoPark Chile S.A., the subsidiary that owns the Chilean assets for a total consideration of US$148,000,000. During 2012, LGI acquired a 20% interest in GeoPark Colombia S.A., the subsidiary that owns the Colombian assets by making a capital contribution in GeoPark Colombia S.A. for an amount of US$14,920,000. In addition, as part of the transaction, US$5,000,000 was transferred directly to the 43 Colombian subsidiary as a loan. The differences between total consideration and the net equity of the Companies as per the book value were recorded as Other Reserve in the Consolidated Statement of Changes in Equity. 43 44 44 Note 26 Borrowings During 2013, the Company issued 10,430 (15,100 in 2012 and 12,028 in 2011) shares to Non-Executive Directors in accordance with contracts as Issued share capital 2013 2012 compensation, generating a share premium of US$100,988 (US$142,492 in 2012 and US$130,733 in 2011). The amount of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period. Under the stock awards programmes and other share based payments, during 2013, 60,000 (30,000 in 2012 and 158,000 in 2011) 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 and US$1,730,000 in 2011). Outstanding amounts as of 31 December Bond GeoPark Latin America Agencia en Chile(a) Methanex Corporation(b) Banco de Crédito e Inversiones(c) Banco de Chile(d) Overdrafts(e) Banco Itaú(f) Bond GeoPark Fell SpA(g) Classified as follows: Non-current On 17 September 2013, 295,599 common shares were allotted to the trustee Current of the Employee Beneficiary Trust (“EBT”), generating a share premium of 299,912 — 2,143 15,002 30 — — — 8,036 7,859 — 10,000 37,685 129,452 317,087 193,032 290,457 26,630 165,046 27,986 US$3,441,689. On 22 October 2012, 976,211 common shares were allotted to The fair value of these financial instruments at 31 December 2013 amounts the trustee of the EBT, generating a share premium of US$4,191,000. On 6 to US$312,208,000 (US$190,188,000 in 2012). The fair values are based October 2011, 601,235 common shares were allotted to the trustee of the EBT on cash flows discounted using a rate based on the borrowing rate of 7.81% in anticipation of the exercise of the 2006 Stock Option Plan (see Note 29). (2012: 9.63%) and are within level 2 of the fair value hierarchy. On 29 October 2013, the Company put into place an irrevocable, non- (a) During February 2013, the Company successfully placed US$300 million discretionary share purchase program for the purchase of its common shares notes which were offered under Rule 144A and Regulation S exemptions of the United States Securities laws. 208 GeoPark 20F The Notes, issued by the Company's wholly-owned subsidiary GeoPark Latin Note 27 America Limited Agencia en Chile ("the Issuer"), were priced at 99.332% and Provisions and other long-term liabilities carry a coupon of 7.50% per annum to yield 7.625% per annum. Final maturity of the notes will be 11 February 2020. The Notes are guaranteed by GeoPark Limited and GeoPark Latin America Cooperatie U.A. and are secured with Asset retirement Deferred a pledge of all of the equity interests of the Issuer in GeoPark Chile S.A. and Amounts in US$ ’000 obligation income Other 3,153 — GeoPark Colombia S.A. and a pledge of certain intercompany loans. Notes were rated single B by both Standard & Poor's and Fitch Ratings. The debt issuance cost for this transaction amounted to US$7,637,000. The net proceeds of the notes were partially used to repay debt of approximately US$170 million, including the existing Regulation S Notes due 2015 and the Itaú loan. The remaining proceeds are being used At 1 January 2011 Addition to provision / Contributions received Amortisation Unwinding of discount At 31 December 2011 Addition to provision / to finance the Company’s expansion plans in the region. The transaction Contributions received extended GeoPark's debt maturity significantly, allowing the Company Acquisition of subsidiaries to allocate more resources to its investment and inorganic growth programs Amortisation in the coming years. (b) The financing obtained in 2007, for development and investing activities Unwinding of discount At 31 December 2012 Addition to provision / 1,947 — 350 5,450 3,440 6,061 — 1,262 16,213 on the Fell Block, was structured as a gas pre-sale agreement with a six Contributions received 7,183 year pay-back period and an interest rate of LIBOR flat. The loan has been Recovery of fully repaid during 2013. abandonments costs Amortisation (c) Facility to establish the operational base in the Fell Block. This facility Unwinding of discount (753) — 1,523 was acquired though a mortgage loan granted by the Banco de Crédito e At 31 December 2013 24,166 Inversiones (BCI), a Chilean private bank (Note 19). The loan was granted 5,000 (1,038) — 3,962 5,550 — (2,143) — 7,369 — — (1,165) — 6,204 — — — — — 100 2,309 — — 2,409 Total 3,153 6,947 (1,038) 350 9,412 9,090 8,370 (2,143) 1,262 25,991 297 7,480 — — — 2,706 (753) (1,165) 1,523 33,076 in Chilean Pesos and is repayable over a period of 8 years. The interest rate The provision for asset retirement obligation relates to the estimation of applicable to this loan is 6.6%. The outstanding amount at 31 December future disbursements related to the abandonment and decommissioning of 2013 is US$212,000 (US$344,000 in 2012). In addition, during 2011, GeoPark oil and gas wells. TdF obtained financing from BCI to start the operations in the newly acquired blocks. The outstanding amount at 31 December 2013 is US$1,931,000 Deferred income and other mainly relates to contributions received to (US$7,515,000 in 2012). This financing was structured as letter of credit and was fully repaid in February 2014. improve the project economics of the gas wells. The amortisation is in line with the related asset. (d) Short term financing obtained in December 2013 and fully repaid in January 2014. The interest rate applicable to this loan was 0.71% per annum. (e) The Group has been granted with credit lines for over US$76,000,000. (f) GeoPark Limited executed a loan agreement with Banco Itaú BBA S.A., Nassau Branch for US$37,500,000. GeoPark used the proceeds to finance the acquisition and development of the La Cuerva and Llanos 62 blocks in Colombia. This loan was fully repaid in February 2013. (g) Private placement of US$133,000,000 of Regulation S Notes on December 2, 2010. The Notes carried a coupon of 7.75% per annum and mature on 15 December 2015. These Notes were fully repaid in March 2013. GeoPark 20F 209 Note 28 Trade and other payables Amounts in US$ ’000 V.A.T Trade payables Payables to related parties(1) Staff costs to be paid Royalties to be paid Taxes and other debts to be paid To be paid to co-ventures Classified as follows: Non-current Current Note 29 Share-based payments 2013 8,074 61,130 8,456 8,551 3,375 9,190 1,201 2012 4,300 IPO Award Programme and Executive Stock Option plan The Group has established different stock awards programmes and other 50,590 share-based payment plans to incentivise the Directors, senior management — and employees, enabling them to benefit from the increased market 5,867 3,909 5,418 2,007 capitalization of the Company. Stock Award Programmes and Other Share Based Payments During 2008, GeoPark Shareholders voted to authorize the Board to use up 99,977 72,091 to 12% of the issued share capital of the Company at the relevant time for the purposes of the Performance-based Employee Long-Term Incentive Plan. 8,344 91,633 — 72,091 Main characteristics of the Stock Awards Programmes are: (1) In December 2012, LGI entered into GeoPark’s operations in Colombia • All employees are eligible. through the acquisition of a 20% of interest in Colombian business. As part • Exercise price is equal to the nominal value of shares. of the transaction, LGI committed to fund the operations in Colombia • Vesting period is four years. through loans (see Note 34). The maturity of these loans is December 2015 • Specific Award amounts are reviewed and approved by the Executive and the applicable interest rate is 8% per annum. Directors and the Remuneration Committee of the Board of Directors. The average credit period (expressed as creditor days) during the year ended Additionally, during 2013 the Company approved two new share-based 31 December 2013 was 58 days (2012: 69 days) compensation programs: i.) a stock awards plan oriented to Managers (non- Top Management) and key employees which qualifies as an equity-settled The fair value of these short-term financial instruments is not individually plan and ii.) a cash awards plan, oriented to all non-management employees determined as the carrying amount is a reasonable approximation of which qualifies as a cash-settled plan. fair value. 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 - Conditions to be able to exercise: • Continue to be an employee • Obtain the Company minimum Production, Adjusted EBITDA and Reserves 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 - Estimated equivalent amount of shares for cash-settled plan: 500,000 Also during 2013, the Company approved a plan named Value creation plan (“VCP”) oriented to Top Management. The VCP establishes awards payables in a variable number of shares with some limitation, subject to certain market conditions, among others, reach certain stock market price for the Company share at vesting date. VCP has been classified as an equity-settled plan. 210 GeoPark 20F 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 2013 2012 2011 2010 2008 Subtotal Stock awards for service contracts Stock options to Executive Directors Shares granted to Awards at the beginning Awards granted in the year 500,000 500,000 500,000 852,100 — 60,000 720,000 — — — — — — Non-Executive Directors VCP — — 10,430 — Awards forfeited Awards Awards at exercised year end 57,000 6,000 16,500 — — — — — — — — — 60,000 500,000 443,000 494,000 835,600 — — 2013 619 1,296 893 2,779 — 5,587 — — 720,000 2,365 10,430 — — — 101 309 8,362 The awards that are forfeited correspond to employees that had left the Group before vesting date. On 23 November 2012, the Remuneration Committee and the board of directors approved granting 720,000 options over ordinary shares of US$0.001 each to the Executive Directors. Options granted vest on the third anniversary of the date on which they are granted and have an exercise price of US$0.001. Other share-based payments As it is mentioned in Note 25, the Company granted 10,430 (15,100 in 2012 and 12,028 in 2011) 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$100,988 (US$142,492 in 2012 and US$130,745 in 2011). In August 2011 the Company issued a total of 180,000 options over US$0.001 shares with an exercise price equal to their nominal value in consideration for certain consultancy services. Charged to net profit 2012 — 55 926 2,929 1,087 4,997 — 257 142 — 5,396 2011 — — 37 2,776 925 3,738 1,429 — 131 — 5,298 GeoPark 20F 211 Note 30 Interests in Joint operations The Group has interests in nine joint operations, which are involved in the exploration of hydrocarbons in Chile and Colombia. GeoPark is the operator of all of the Chilean blocks. Joint operation Subsidiary Interest(*) Assets PP&E / E&E The following amounts represent the Company’s share in the assets, liabilities Other assets and results of the joint operations which have been consolidated line by line Total Assets in the consolidated statement of financial position and statement of income: Chile Liabilities Current liabilities Total Liabilities Net Assets/(Liabilities) Joint operation Tranquilo Block Otway Block Sales Flamenco Campanario Isla Norte Block GeoPark TdF S.A. 50% 2013 Block GeoPark TdF S.A. 50% 2013 Block GeoPark TdF S.A. 60% 2013 42,048 17,172 — — 42,048 17,172 (2,537) (2,537) 39,511 243 (239) (405) (405) 16,767 — — 4,497 — 4,497 (303) (303) 4,194 — — GeoPark Magallanes Ltda. 29% 29% GeoPark Magallanes Ltda.(1) 25% 100% Net loss 2013 2012 2013 2012 period, the above balances and operations were consolidated at 100% (*) As the activity on the three blocks corresponds to the first exploratory Subsidiary Interest Assets PP&E / E&E Other assets Total Assets Liabilities Current liabilities Total Liabilities Net Assets/(Liabilities) Sales Net loss 15,255 210 15,465 (391) (391) 15,074 — (275) 13,328 1,467 14,795 (3,252) (3,252) 11,543 — (544) 6,009 175 6,184 (48) (48) 6,136 — (100) 6,516 1,326 7,842 (2,412) (2,412) 5,430 — (386) (see Note 31). Colombia 31 December 2013 Yamu/ Joint operation Block Block Block Block Llanos 17 Carupana Llanos 34 Llanos 32 GeoPark GeoPark GeoPark GeoPark Colombia Colombia Colombia Colombia Subsidiary SAS SAS 75%/ SAS SAS Interest Assets PP&E / E&E Other assets Total Assets Liabilities Current liabilities Total Liabilities Net Assets / (Liabilities) Sales Net profit / (loss) 36.84% 54.50% 45% 10% 6,448 29 6,477 — — 6,477 1,407 (544) 15,476 482 15,958 51,963 1,129 53,092 — — — — 15,958 17,727 2,127 53,092 78,390 39,192 4,993 — 4,993 — — 4,993 5,507 1,035 (1) Included for comparative purposes. See Note 20. 212 GeoPark 20F 31 December 2012 In Colombia, royalties on production are payable to the Colombian Yamu/ Government and are determined on a field-by-field basis using a level of Llanos 17 Carupana Llanos 34 Llanos 32 production sliding scale and a rate which ranges between 6%-8%. The Joint operation Block Block Block Block Colombian National Hydrocarbons Agency (“ANH”) also has an additional GeoPark economic right equivalent to 1% of production, net of royalties. Additionally, Colombia GeoPark under the terms of the Winchester Stock Purchase Agreement, we are GeoPark and Colombia GeoPark obligated to make certain payments to the previous owners of Winchester Subsidiary Luna SAS Luna SAS SAS Luna SAS based on the production and sale of hydrocarbons discovered by exploration Interest Assets PP&E / E&E Other assets Total Assets Liabilities Current liabilities Total Liabilities Net assets / (Liabilities) Sales Net profit / (loss) 36.84% 75%/ 54.50% wells drilled after October 25, 2011. These payments involve both an earnings 45% 10% based measure and an overriding royalty equal to an estimated 4% carried interest on the part of the vendor. As at the balance sheet date and based 3,872 144 4,016 (224) (224) 3,792 144 144 12,626 25,178 26 72 4,384 1,484 on preliminary internal estimates of additions of 2P reserves since acquisition, the Company’s best estimate of the total commitment over the remaining 12,652 25,250 5,868 life of the concession is a range of US$40 million - US$50 million — — — — (assuming a discount rate of 10% and oil price of US$94 per barrel). During (1,509) 2013, the Company has accrued and paid US$11.5 million and US$7.8 (1,509) million, respectively. 12,652 23,283 4,034 25,250 10,362 3,767 4,359 2,900 1,207 (b) Capital commitments Chile As of 31 December 2013 the only remaining commitments in Chile are related Capital commitments are disclosed in Note 31 (b). to Tierra del Fuego blocks. The future investment commitments assumed Note 31 Commitments by GeoPark outstanding are: • Flamenco Block: 6 exploratory wells (US$19,440,000) • Campanario Block: 8 exploratory wells (US$30,666,000) • Isla Norte Block: 3 exploratory wells and 221 km2 of seismic surveys (a) Royalty commitments In Argentina, crude oil production accrues royalties payable to the Provinces (US$13,857,000) of Santa Cruz and Mendoza equivalent to 12% on estimated value at The investments made in the first exploratory period will be assumed 100% well head of those products. This value is equivalent to final sales price less transport, storage and treatment costs. by GeoPark. In Argentina crude oil sales accrue private royalties payable to EPP Colombia The Llanos 32 Block Consortium has committed to drill two exploratory wells Petróleo S.A. (2.5% on invoiced amount of crude oil obtained from wells at between 2013 and 2014. “Del Mosquito”, Province of Santa Cruz, Argentina) and to Occidental Petroleum Argentina INC, formerly Vintage Argentina Ltd. (8% on invoiced The Llanos 17 Block Consortium has committed to drill either two exploratory amount of crude oil obtained from wells at “Loma Cortaderal” and “Cerro wells or one exploratory well and perform 3D seismic between 2013 and Doña Juana”, Province of Mendoza, Argentina). 2014. The joint operation estimates that the remaining commitment amounts In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties are calculated at 5% of crude oil production and 3% of gas The Llanos 62 Block (100% working interest) has committed to drill two production. In the Flamenco Block, royalties are calculated at 5% of gas exploratory wells before August 2014. The remaining commitment amounts production. to US$3,000,000. to US$1,225,000 at GeoPark’s working interest (36.84%). GeoPark 20F 213 Brazil On 14 May 2013, the ANP awarded GeoPark seven new concessions in Brazil Note 32 Related parties in an international bidding round, Round 11. For these seven concessions, GeoPark committed to invest a minimum of US$15,300,000 (including bonuses and work program commitment) during the first three years of the Controlling interest The main shareholders of GeoPark Limited, a company registered in Bermuda, exploratory period for the concessions. as of 31 December 2013, are: On 28 November 2013, the ANP awarded GeoPark two new concessions in a new international bidding round, Round 12. For these two concessions, GeoPark have committed to invest a minimum of US$4,000,000 (including bonus and work program commitments) during the first exploratory period (see Note 34) (c) Operating lease commitments – Group company as lessee The Group leases various plant and machinery under non-cancellable operating lease agreements. 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 The Group also leases offices under non-cancellable operating lease Charles Schwab & Co. agreements. The lease terms are between 2 and 3 years, and the majority of Other shareholders lease agreements are renewable at the end of the lease period at market rate. Common shares 7,533,907 7,156,269 4,984,394 3,456,594 2,241,650 2,171,363 2,097,257 1,393,361 12,826,819 43,861,614 Percentage of outstanding common shares 17.18% 16.32% 11.36% 7.88% 5.11% 4.95% 4.78% 3.18% 29.24% 100.00% During 2013 a total amount of US$19,110,000 (US$ 4,531,000 in 2012 and (1) Held directly and indirectly through GP Investments LLP, Vidacos US$3,313,000 in 2011) was charged to the income statement and Nominees Limited and Globe Resources Group Inc., all of which are controlled US$37,263,000 of operating leases were capitalised as Property, plant and by Mr. O’Shaughnessy. equipment (US$32,706,000 in 2012 and US$28,132,000 in 2011). (2) Held by Energy Holdings, LLC, which is controlled by James F. Park, a The future aggregate minimum lease payments under non-cancellable Mr. Park does not reflect the 782,702 common shares held as of January 10, operating leases are as follows: 2014 in the employee benefit trust described under ‘‘Management— member of our Board of Directors. The number of common shares held by Amounts in US$ ’000 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 Total minimum lease payments Compensation—Employee Benefit Trust’’. 2013 2012 (3) Held through certain private investment funds managed and controlled by Cartica Management, LLC. The common shares reflected as being held 68,817 56,556 31,145 505 26,464 3,709 by Mr. Quamme include 7,422 common shares held by him personally. Mr. Steven Quamme, one of our principal shareholders and a member of our 443 895 board of directors, is the Senior Managing Director of Cartica Management, LLC, and therefore may be deemed to have voting and investment power 157,023 31,511 over the common shares of GeoPark held by Cartica Management, LLC. (4) IFC Equity Investments voting decisions are made through a portfolio management process which involves consultation from investment officers, credit officers, managers and legal staff. (5) Held through various funds managed by Moneda A.F.I. (Administradora de Fondos de Inversión), an asset manager. (6) Held through Socoservin Overseas Ltd, which is controlled by Juan Cristóbal Pavez. The common shares reflected as being held by Mr. Pavez include 8,559 common shares held by him personally. 214 GeoPark 20F Balances outstanding and transactions with related parties Transaction in the year Balances at year end Related Party Relationship Account (Amounts in ’000) 2013 To be recovered from co-ventures Payables account To be paid to co-venturers Financial expenses 2012 To be recovered from co-ventures Prepayment and other receivables To be paid to co-venturers Exploration costs Administrative costs 2011 To be recovered from co-ventures Prepayment and other receivables Exploration costs (*) Corresponding to consultancy services. — — — 112 — — 31 219 — — 138 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. 15,508 (8,456) (1,201) — 8,773 31,138 (2,007) — — 537 6,000 Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations LGI Partner Joint Operations Joint Operations Carlos Gulisano Carlos Gulisano Non-Executive Director(*) Non-Executive Director(*) Joint Operations Joint Operations LGI — Carlos Gulisano Partner Non-Executive Director(*) GeoPark 20F 215 Note 33 Fees paid to Auditors Amounts in US$ ’000 Fees payable to the Group’s auditors for the audit of the consolidated financial statements(*) Fees payable to the Group’s auditors for the review of interim financial results Fees payable for the audit of the Group’s subsidiaries pursuant to legislation Non-audit services Fees paid to auditors income approach (being the net present value of expected future cash flows) was adopted to determine the fair values of the mineral interest. Estimates of expected future cash flows reflect estimates of projected future revenues, 2013 2012 2011 production costs and capital expenditures based on our business model. Under the terms of the sale and purchase agreement entered into in 2012 in respect of the acquisition of Winchester Luna, the Company has to make 668 346 120 certain payments to the former owners arising from the production and sale of hydrocarbons discovered by exploration wells drilled after 25 October 2011 on the working interests of the companies at that date. These payments 150 52 32 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. 273 337 298 713 1,428 1,409 113 239 504 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: (*) Include fees related to the IPO process Winchester Amounts in US$ ’000 Hupecol Luna Total Non-audit services relates to tax services for US$292,000 (US$121,000 Cash (including working in 2012 and US$123,000 in 2011) and due diligence and other services for capital adjustments) US$45,000 (US$592,000 in 2012 and US$116,000 in 2011). Note 34 Business transactions Acquisitions in Colombia On 14 February 2012, GeoPark acquired two privately-held exploration and Total consideration Cash and cash equivalents Property, plant and equipment (including mineral interest) Trade receivables Prepayments and other receivables Deferred income tax assets production companies operating in Colombia, Winchester Oil and Gas S.A. Inventories and La Luna Oil Company Limited S.A. (“Winchester Luna”). For accounting Trade payables and other debt purposes, these acquisitions were computed as if they had occurred on 1 February 2012. Borrowings Provision for other long-term liabilities On 27 March 2012, a second acquisition occurred with the purchase of Total identifiable net assets Hupecol Cuerva LLC (“Hupecol”), a privately-held company with two exploration and production blocks in Colombia. For accounting purposes, Bargain purchase gain on acquisition of subsidiaries(1) this acquisition was computed as if it had occurred on 1 April 2012. 79,630 79,630 976 73,791 4,402 5,640 10,344 10,596 (20,487) — 32,243 32,243 5,594 111,873 111,873 6,570 37,182 4,098 110,973 8,500 2,983 5,262 1,612 (11,981) (1,368) 8,623 15,606 12,208 (32,468) (1,368) (5,632) 79,630 (2,738) 40,644 (8,370) 120,274 — 8,401 8,401 In accordance with the acquisition method of accounting, the acquisition a full market price for the proved reserves but received a discount on cost was allocated to the underlying assets acquired and liabilities assumed the probable and possible reserves and resource base acquired due to the based primarily upon their estimated fair values at the date of acquisition. An vendor’s limited ability to fund the future development of these assets. (1) The bargain purchase gain is related to the fact that the Company paid 216 GeoPark 20F The purchase price allocation above mentioned is final. ("Rio das Contas"), the direct owner of 10% of the BCAM-40 Block (the "Block"), which includes the shallow-depth offshore Manati Field in the Acquisition-related costs have been charged to administrative expenses in Camamu-Almada basin. the consolidated income statement for the year ended 31 December 2012. LGI partnership The Manati Field is a strategically important, profitable upstream asset in Brazil and currently provides approximately 50% of the gas supplied to On 12 March 2010, LGI and the Company agreed to form a new strategic the northeastern region of Brazil and more than 75% of the gas supplied to partnership to jointly acquire and develop upstream oil and gas projects in Salvador, the largest city and capital of the northeastern state of Bahia. Latin America. The field is largely developed with existing producing wells and an extensive pipeline, treatment and delivery infrastructure and is not expected to During 2011, GeoPark and LGI entered into several agreements through require significant future capital expenditures to meet current production which LGI acquires an equity interest in the Chilean Business of the Group. estimates. Additional reserve development may be possible. In December 2012, LGI has also joined GeoPark’s operations in Colombia The Manati Field is operated by Petrobras (35% working interest), through the acquisition of a 20% interest in GeoPark Colombia S.A., a the Brazilian national company, largest oil and gas operator in Brazil and company that holds GeoPark’s Colombian assets and which includes interests internationally-respected offshore operator. Other partners in the block in 10 hydrocarbon blocks. A capital contribution in GeoPark Colombia S.A. include Queiroz Galvao Exploração e Produção (45% working interest) and for an amount of US$14,920,000 was made in 2013. In addition, as part Brasoil Manati Exploração Petrolífera S.A. (10% working interest). of the transaction, US$5,000,000 was transferred directly to the Colombian subsidiary as a loan. GeoPark has agreed to pay a cash consideration of US$140 million at closing, which will be adjusted for working capital with an effective date of In addition, in March 2013 GeoPark and LGI announced their agreement April 30, 2013. The agreement also provides for possible future contingent to extend their strategic alliance to build a portfolio of upstream oil and gas payments by GeoPark over the next five years, depending on the economic assets throughout Latin America through 2015. performance and cash generation of the Block. On 26 March 2014 the Further, on 8 January 2014, following an internal corporate reorganization consented with the transaction. The closing of the acquisition occurred on Brazilian National Petroleum, Natural Gas and Biofuels Agency ("ANP") of our Colombian operations, GeoPark Colombia Coöperatie U.A. and GeoPark March 31, 2014. Latin America entered into a new members’ agreement with LGI, or the LGI Colombia Members’ Agreement, that sets out substantially similar rights and The Company afforded the acquisition from existing cash resources as of obligations to the LGI Colombia Shareholders’ Agreement in respect of our 31 December 2013 (see Note 3) and through its Brazilian subsidiary's entrance oil and gas business in Colombia. Entry in Brazil Acquisition in Brazil into a loan pre-approved on February 2014 by Itaú BBA International for US$70.5 million. The interest rate applicable to this loan will be LIBOR plus 3.9% per annum. The interests will be paid semi-annually; principal will be cancelled semi-annually with one year grace period. The facility agreement includes customary events of default, and subject our Brazilian subsidiary GeoPark entered into Brazil with the acquisition of a ten percent working to customary covenants, including the requirement that it maintain a ratio interest in the offshore Manati gas field ("Manati Field"), the largest natural of net debt to EBITDA of up to 3.5x the first two years and up to 3.0x gas producing field in Brazil. On May 14, 2013, GeoPark executed a stock thereafter. The credit facility also limits the borrower’s ability to pay dividends purchase agreement ("SPA") with Panoro Energy do Brazil Ltda., the subsidiary if the ratio of net debt to EBITDA is greater than 2.5x. The facility can be of Panoro Energy ASA, ("Panoro"), a Norwegian listed company with assets prepaid in whole or in part, at any time, subject to a pre-payment fee to in Brazil and Africa, to acquire all of the issued and outstanding shares of its be determined under the contract. wholly-owned Brazilian subsidiary, Rio das Contas Produtora de Petróleo Ltda GeoPark 20F 217 The Manati Field acquisition provides GeoPark with: According to the terms of the Court’s injunction, the ANP will first need to take certain actions, such as conducting studies that prove that drilling - A solid foundational platform in Brazil to support future growth and unconventional resources will not contaminate the dams and aquifers in the expansion in Brazil - one of the world's most attractive hydrocarbon regions. region. On February 21, 2014, GeoPark Brazil requested that the board of - Participation in an economically-attractive and strategic asset representing the ANP suspend the execution of the concession agreement (which entails the largest non-associated gas producing field in Brazil, with a gross delivery of the financial guarantee and performance guarantee and production of over 200 million cubic feet per day of gas and a secure payment of the signing bonus) for six months with a possible extension of attractively-priced long term off take contract that covers 75% of proven an additional six months, or until a firm court decision is reached that does reserves (100% of proven developed reserves). not prevent GeoPark Brazil from entering into the concession agreement. - A low-risk and fully-developed producing gas field with no significant On April 16, 2014, the ANP’s Board enacted a resolution stating that drilling or capital expenditure investments expected. all proceedings related to the award of the concession of Block PN-T-597 - A valuable partnership with Petrobras, the largest operator in Brazil. to GeoPark Brazil were suspended. - An established geoscience and administrative team to manage the assets - and seek new growth opportunities. New operations in Brazil On 14 May 2013, the Company has been awarded seven new licenses in the Note 35 Agreement with Methanex Brazilian Round 11 of which two are in the Reconcavo Basin in the State In March 2012, the Company and Methanex signed a third addendum and of Bahia and five are in the Potiguar Basin in the State of Rio Grande do Norte. amendment to the Gas Supply Agreement to incentivise the development of gas reserves. Through this new agreement, the Company completed The licensing round was organized by the ANP and all proceedings and the drilling of five new gas wells during 2012. Methanex contributed to the bids have been made public. On 17 September 2013, the winning bids were cost of drilling the wells in order to improve the project economics. The approved by the ANP. Company fulfilled all the commitments under this agreement. For its winning bids on the seven blocks, GeoPark has committed to invest The Agreement also includes monthly commitments for delivering certain a minimum of US$15.3 million (including bonus and work program volumes of gas and in case of failure; the Company could satisfy the commitment) during the first 3 years of the exploratory period. The new obligation from future deliveries without penalty during a period of three blocks cover an area of approximately 54,850 acres. months. As of 31 December 2012, the accrued penalty for under delivered volumes amount to US$1.7 million which was recorded in Provisions On November 28, 2013, the ANP awarded GeoPark with two new concessions for other liabilities in the Statement of Financial Position. in a new international bidding round, Round 12, in the following basins: • Parnaíba Basin in the State of Maranhão: PN-T-597 Concession; and On August 30, 2013, the Company signed a fourth amendment to the Methanex Gas Supply Agreement, pursuant to which Methanex has • Sergipe Alagoas Basin in the State of Alagoas: SEAL-T-268 Concession. committed, for a period of six months commencing September 15, 2013, to purchase an increased volume, in a total amount of 400,000 SCM/d per In Brazil, GeoPark Brasil Exploração e Produção de Petróleo (“GeoPark Brazil”) month (subject to reduction for deliveries above 200,000 SCM/d to Methanex is currently a party to a legal proceeding related to the concession agreement or ENAP made between April 29 and September 15, 2013), at an additional of Block PN-T-597 that the ANP initially awarded to GeoPark Brazil in the 12th price per month of US$1.50 per mmbtu for volumes in excess of 180,000 oil and gas bidding round. As a result of a class action filed by the Federal SCM/d, or an additional price per month of US$2.00 per mmbtu in any month Prosecutor’s Office, an injunction was issued by a Brazilian Federal Court in which we commit to deliver at least 500,000 SCM/d (subject to certain against the ANP, the Federal Government and GeoPark Brazil on December exceptions based on methanol prices). The amendment also provides for 13, 2013. Due to the injunction GeoPark Brazil could not proceed to execute temporary DOP and TOP thresholds of 100% and 50%, respectively. As of 31 the concession agreement, and cannot do so until the injunction is lifted. December 2013, the Company has fulfilled the delivery volume commitment. 218 GeoPark 20F Note 36 Note 37 Drilling operations start-up in Tierra del Fuego Strategic alliance with Tecpetrol in Brazil In April 2013, the Company has started the exploration drilling in Tierra del On 30 September 2013, the Company and Tecpetrol S.A. ("Tecpetrol") Fuego in Chile in its partnership with Empresa Nacional de Petroleo de Chile announced the formation of a new strategic alliance to jointly identify, study ("ENAP") with the spudding of the Chercán 1 well on the Flamenco Block. and potentially acquire upstream oil and gas opportunities in Brazil, with a Chercán 1 is the first of 21 exploratory wells on the Flamenco, Campanario specific focus on the Parnaiba, Sao Francisco, Reconcavo, Potiguar and and Isla Norte Blocks in Tierra del Fuego as part of an estimated US$100 Sergipe- Alagoas basins. million investment commitment during the First Exploration Period. As of March 2014, 8 wells have been drilled and 1,500 sq km of 3D seismic oilfield and steel conglomerate) with an extensive track-record as an have been carried out over the three blocks; which represent the total 3D oil and gas explorer and operator with its portfolio of assets currently Tecpetrol is the oil and gas subsidiary of the Techint Group (a multinational seismic program commitment. in Argentina, Peru, Colombia, Ecuador, Mexico, Bolivia, Venezuela and the United States, and with a current net production of over 85,000 barrels of oil equivalent per day. At 31 December 2013, there is no accounting impact of the creation of the alliance. GeoPark 20F 219 Note 38 Supplemental information on oil and gas activities (unaudited) Table 1 - Costs incurred in exploration, property acquisitions and development(1) The following table presents those costs capitalized as well as expensed that The following information is presented in accordance with ASC No. 932 were incurred during each of the years ended as of 31 December 2013, “Extractive Activities - Oil and Gas”, as amended by ASU 2010 - 03 “Oil and 2012 and 2011. 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 the geological and geophysical costs, costs necessary for retaining undeveloped 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 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 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 Amounts in US$ ’000 Year ended 31 December 2011 Acquisition of properties Proved Unproved Total property acquisition Exploration Development Total costs incurred 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 Chile Colombia Argentina Total — — — 38,601 60,002 98,603 — — — — — — — — — 3,671 147 3,818 — — — 42,272 60,149 102,421 (1) Includes capitalized amounts related to asset retirement obligations. 220 GeoPark 20F Table 2 - Capitalized costs related to oil and gas producing activities The following table presents the capitalized costs as at 31 December 2013, 2012 and 2011, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates. 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 capitalized 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 capitalized amounts related to asset retirement obligations. Amounts in US$ ’000 At 31 December 2011 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 capitalized 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 Chile Colombia Argentina Total 46,259 166,679 32,697 37,755 283,390 (67,559) 215,831 — — — — — — — 843 5,277 199 4,385 10,704 (4,673) 6,031 47,102 171,956 32,896 42,140 294,094 (72,232) 221,862 GeoPark 20F 221 Table 3 - Results of operations for oil and gas producing activities The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended 31 December 2013, 2012 and 2011. Income tax for the years presented was calculated utilizing the statutory tax rates. 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 — — — — (1,702) — — (1,702) 579 (1,123) 338,353 (93,825) (17,239) (111,064) (16,253) (1,523) (68,579) 140,934 (32,808) 108,126 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 Amounts in US$ ’000 Year ended 31 December 2013 Net revenue Production costs Operating costs Royalties and other Total production costs Exploration expenses Accretion expense(1) 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 2012 Net revenue Production costs Operating costs Royalties and other Total production costs Exploration expenses Accretion expense(1) Depreciation, depletion and amortization Results of operations before income tax Income tax Results of oil and gas operations 222 GeoPark 20F Amounts in US$ ’000 Year ended 31 December 2011 Net revenue Production costs Operating costs Royalties and other Total production costs Exploration expenses Accretion expense(1) Depreciation, depletion and amortization Results of operations before income tax Income tax Results of oil and gas operations (1) Represents accretion of ARO liability. Chile Colombia Argentina Total 110,103 (23,623) (4,634) (28,257) (8,487) (178) (24,958) 48,223 (7,233) 40,990 — — — — — — — — — — 1,477 111,580 (203) (209) (412) (1,579) (172) (886) (1,572) 550 (1,022) (23,826) (4,843) (28,669) (10,066) (350) (25,844) 46,651 (6,683) 39,968 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 and DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton prepared its proved oil and natural gas reserve 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 to Proved developed reserves are proved reserves that can reasonably be Extractive Activities—Oil and Gas (formerly SFAS no. 69 Disclosures about reserves estimation as of 31 December 2013, 2012 and 2011 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 223 The estimated GeoPark net proved reserves for the properties evaluated as of 31 December 2013, 2012 and 2011 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf): Net proved developed Chile(1) Colombia(2) Argentina Total consolidated Net proved undeveloped Chile(1) Colombia(3) Argentina Total consolidated Total proved reserves As of 31 December 2013 As of 31 December 2012 As of 31 December 2011 Oil and Oil and Oil and condensate Natural gas condensate Natural gas condensate Natural gas (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) (MMcf) 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 2,133.2 — — 2,133.2 24,476.0 — — 24,476.0 16,813.0 3,120.9 32,681.0 — — 16,813.0 29,581.0 — — 3,120.9 5,254.1 — — 32,681.0 57,157.0 (1) Fell Block accounts for 100% of the reserves (LGI owns a 20% interest). (2) Llanos 34 Block and Cuerva Block account for 58% and 36% (31% and 53% in 2012) of the proved developed reserves, respectively (LGI owns a 20% interest). (3) Llanos 34 Block and Cuerva Block account for 74% and 23% (72% and 25% in 2012) of the proved undeveloped reserves, respectively (LGI owns a 20% interest). 224 GeoPark 20F Chile 5,349.9 (1,253.8) 2,022.0 (864.0) 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 Colombia Argentina — — — — — — — 7,522.8 (895.8) 6,627.0 (277.0) 5,210.0 (2,133.4) 9,426.6 — — — — — — — — — — — — — — Total 5,349.9 (1,253.8) 2,022.0 (864.0) 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 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 2010(1) Increase (decrease) attributable to: Revisions(2) Extensions and discoveries Production Reserves as of 31 December 2011 Increase (decrease) attributable to: Revisions(3) Extensions and discoveries Purchases of minerals in place Production Reserves as of 31 December 2012 Increase (decrease) attributable to: Revisions Extensions and discoveries(4) Production Reserves as of 31 December 2013 (1) Includes 1,377 of developed reserves. (2) The revisions are primarily due to the following adjustments in the Fell Block: • Monte Aymond Field – Proved undeveloped oil reserves: Reduced expected recovery based on offset performance (approximately -600 mbo); and, • Other miscellaneous revisions, including the reduced condensate related to the gas field reserves reductions. (3) The revisions are primarily 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. (4) Primarily due to 2013 discoveries in Llanos 34 (Taro Taro, Tigana and Tigana Sur) and Yamú (Potrillo). GeoPark 20F 225 Net proved reserves (developed and undeveloped) of natural gas: Millions of cubic feet Reserves as of 31 December 2010(1) Increase (decrease) attributable to: Revisions(2) Extensions and discoveries Production Reserves as of 31 December 2011 Increase (decrease) attributable to: Revisions(3) Extensions and discoveries Purchases Production Reserves as of 31 December 2012 Increase (decrease) attributable to: Revisions(4) Extensions and discoveries Production Reserves as of 31 December 2013 Chile 76,974.0 (15,817.0) 5,690.0 (9,690.0) 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 Colombia Argentina — — — — — — — — — — — — — — — — — — — — — — — — — — — — Total 76,974.0 (15,817.0) 5,690.0 (9,690.0) 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 (1) Includes 30,691 of developed reserves. (3) The revisions are primarily due to the effect of having reduced the (2) The revisions are primarily due to the following adjustments in the Company’s future gas production profile in Chile because of expected Fell Block: reduced deliveries to the Methanex plant. This causes a significant portion • Dicky Field – Proved developed gas reserves: Reduced proved developed of the gas reserves to be produced below an economic level later in the reserves based on performance (approximately -2100 mmcf); productive life of the Fell Block and after the expiration of the Methanex • Dicky Oeste Field – Proved undeveloped gas reserves: Reduced expected Gas Supplies Agreement. recovery based on offset performance (approximately -3750 mmcf); (4) The revisions are primarily due to adjustments in the Fell Block as a • Ovejero Field – Proved developed gas reserves: Producing well shut-in - response to a workover in Monte Aymond field, and associated gas from Moved reserves to probable (approximately -1000 mmcf); drilling campaigns in Konawentru and Yagán Norte fields. • Pampa Field – Proved undeveloped gas reserves: Reduced recovery based on offset performance (approximately -5500 mmcf); • Santiago Norte Field – Proved undeveloped gas reserves: Reduced recovery Revisions refer to changes in interpretation of discovered accumulations and some technical / logistical needs in the area obliged to modify the timing and based on offset performance (approximately -3000 mmcf); and development plan of certain fields under appraisal and development phases. • Other miscellaneous revisions. 226 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 proved oil and gas reserves interpreted as an estimate of the market value of the Company’s reserves. The following table discloses estimated future net cash flows from future The purpose of this information is to give standardized data to help the production of proved developed and undeveloped reserves of crude oil, users of the financial statements to compare different companies and make condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas certain projections. It is important to point out that this information does Reporting rules and ASC 932 of the FASB Accounting Standards Codification not include, among other items, the effect of future changes in prices, costs (ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 and tax rates, which past experience indicates that are likely to occur, as Disclosures about Oil and Gas Producing Activities), such future net cash flows well as the effect of future cash flows from reserves which have not yet were estimated using the average first day- of-the-month price during been classified as proved reserves, of a discount factor more representative the 12-month period for 2013, 2012 and 2011 and using a 10% annual discount of the value of money over the lapse of time and of the risks inherent to factor. Future development and abandonment costs include estimated drilling the production of oil and gas. These future changes may have a significant costs, development and exploitation installations and abandonment costs. impact on the future net cash flows disclosed below. For all these reasons, These future development costs were estimated based on evaluations this information does not necessarily indicate the perception the Company made by the Company. The future income tax was calculated by applying has on the discounted future net cash flows derived from the reserves of the statutory tax rates in effect in the respective countries in which we have hydrocarbons. interests, as of the date this supplementary information was filed. Amounts in US$ ’000 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 At 31 December 2011 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 Argentina Total 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) 202,449 681,269 (130,786) (112,014) (76,544) 361,925 (76,332) 285,603 686,227 (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 — — — — — — — — — — — — — — — — — — — — — — — — — — — — 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) 336,094 681,269 (130,786) (112,014) (76,544) 361,925 (76,332) 285,603 GeoPark 20F 227 Chile 226,784 (83,199) 145,391 (39,039) 87,266 56,566 (114,297) (20,058) 28,085 (1,896) 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 Colombia Argentina — — — — — — — — — — — (10,015) — — — — — 143,660 — — — 133,645 (144,087) 4,754 (42,667) 186,738 39,922 (9,928) (17,827) 23,242 173,792 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — Total 226,784 (83,199) 145,391 (39,039) 87,266 56,566 (114,297) (20,058) 28,085 (1,896) 285,603 (120,346) 45,100 (73,255) 108,768 57,055 (174,757) 143,660 23,250 36,215 4,801 336,094 (273,080) (171) (161,427) 250,686 123,905 27,461 (13,725) 47,909 337,652 Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves Amounts in US$ ’000 Present value at 31 December 2010 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 Other changes 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 228 GeoPark 20F Exhibit 12.1 Exhibit 12.2 CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO 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, and for, the periods presented in this report; as of, 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)) for the company and have: in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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 ensure that material information relating to the company, including its to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those 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. [Reserved] b. [Reserved] 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 effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the company’s internal control over d. Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and the 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, 5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): of 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 and report financial information; and summarize 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 employees who have a significant role in the company’s internal control over financial reporting. over financial reporting. Date: April 30, 2014 /s/ James F. Park James F. Park Chief Executive Officer (Principal Executive Officer) Date: April 30, 2014 /s/Andrés Ocampo Andrés Ocampo Chief Financial Officer (Principal Financial Officer) GeoPark 20F 229 Exhibit 13.1 Exhibit 13.2 CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO 18 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, 2013 (the “Report”), I, James F. Park, certify fiscal year ended December 31, 2013 (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, 2014 /s/ James F. Park James F. Park Chief Executive Officer (Principal Executive Officer) Date: April 30, 2014 /s/ Andrés Ocampo Andrés Ocampo Chief Financial Officer (Principal Financial Officer) 230 GeoPark 20F GeoPark 20F 231 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. Steven J. Quamme | Non-Executive Director Mr. Quamme has been a member of our board of directors since June 2011. He has 25 years of experience as a fund manager, securities and corporate lawyer, and investment banker. Mr. Quamme holds a B.a. in economics from northwestern university and a J.d. from the northwestern university school of law, where he is a member of the law school Board. Mr. Quamme is a member of the board of directors of cartica Management, llc, as well as the board of trustees of the potomac school and of the sibley Memorial Hospital Foundation. He has previously served as a member of the boards of directors of Equivest Finance, Milestone Merchant partners, llc, Kerrco inc., atlantic Entertainment Group, rausch industries, rompetrol, and Einstein noah Bagel corp, lp. From 2005 to 2007, Mr. Quamme served as the chief operating officer of Breeden partners, a corporate governance fund. From 2002 to 2007, Mr. Quamme also served as senior Managing director of richard c. Breeden & co., a professional services firm, which focuses on corporate governance and crisis management. in 2000, Mr. Quamme founded Milestone Merchant partners, a merchant bank based in Washington d.c., where he served as its cEo until 2005. Mr. Quamme is presently a co-founder and senior Managing director of cartica Management, a registered investment advisor focused on emerging markets and a Geopark shareholder. 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. 232 annual report 2013 directors, secretary & advisors 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 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) steven J. Quamme (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 las condes, santiago chile | + 56 2 242 9600 pedro aylwin chiorrini 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 designed by: chiappini + Becker tel. +54 11 4314 7774 www.ch-b.com photographer: diego dicarlo, Geologist annual rEport 2013 WWW.GEo-parK.coM 

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