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Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for

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i.	The area of the reservoir considered as proved includes:

A.	The area identified by drilling and limited by fluid contacts, if any, and

B.	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

ii.	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

iii.	Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

iv.	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

A.	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

B.	The project has been approved for development by all necessary parties and entities, including governmental entities.

v.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

•	Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

i.	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

ii.

Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

iii.	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

iv.	See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of section 210.4-10(a) of Regulations S-X.

•	Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

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i.	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

ii.	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

iii.	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

iv.	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

v.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

vi.

Pursuant to paragraph (a)(22)(iii) of section 210.4-10(a) of Regulations S-X, where direct observation has defined a HKO elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and as changes due to increased availability of geoscience (geological, geophysical and geochemical), engineering and economic data are made to estimated ultimate recovery ("EUR") with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

•	Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

•	Probabilistic estimate. The method of estimating reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience, engineering or economic data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

•	Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

i.	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; and

ii.	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

•	Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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i.	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

ii.	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

iii.

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of section 201.4-10(a) of Regulation S-X, or by other evidence using reliable technology establishing reasonable certainty.

•	in Colombia, we continued to focus on developing our producing conventional light oil fields, including Costayaco and Moqueta, and on the generation of exploration prospects;

•	in Argentina, we continued to focus on developing our producing fields, including the Surubi and Puesto Morales fields;

•	in Brazil, we added three onshore blocks to our core operating area in the Recôncavo Basin in the 2013 Brazil bid round 11;

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in Peru, we completed drilling and testing of the Vivian formation sandstone reservoir in the Bretaña Norte 95-2-1XD exploration well and drilled a horizontal side-track extension of this well, completed a preliminary Front End Engineering Design ("FEED") study for the Bretaña field development and completed a 382 kilometer 2-D seismic program to provide a more detailed map of the Bretaña structure, along with maturing separate independent exploration leads on Block 95. Significant probable and possible reserves were added in Peru during 2013. We also received regulatory approval for the assignment of the remaining 40% working interest of Block 95; and received regulatory approval to assume operatorship of Blocks 123 and 129.

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•	3.4 million gross acres (2.7 million net) in Colombia covering 17 exploration and production contracts, five of which were producing and 15 of which were operated by Gran Tierra (excludes 1.0 million gross and net acres on five blocks where relinquishments were subject to approval and acreage changes, also subject to approval, on a further three blocks);

•	1.3 million gross acres (0.9 million net) in Argentina covering 11 exploration and production contracts, eight of which were producing and nine of which were operated by Gran Tierra;

•	47,734 gross acres (47,734 net) in Brazil covering seven exploration blocks, one of which was producing and all of which were operated by Gran Tierra; and

•	5.8 million gross acres (5.8 million net) in Peru covering five exploration licenses, none of which were producing and all of which were operated by Gran Tierra.

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•	Position in countries that are welcoming to foreign investment, provide attractive fiscal terms, have stable legal systems, offer opportunities that we believe have been previously ignored or undervalued, and have an active market with many available deals;

•	Build a balanced portfolio of production, development and exploration assets and opportunities, with a drilling inventory that balances risks and rewards to create value;

•	Retain operatorship of assets whenever possible to retain control of work programs, budgets, prospect generation, drilling operations and development activities; non-operating positions will be taken when operators add a strategic advantage to our business growth;

•	Engage qualified, experienced and motivated professionals;

•	Establish an effective local presence, with strong constructive relationships with host governments, ministries, agencies and communities in which we operate;

•	Consolidate land and properties in close proximity to build operating efficiency; and

•	Manage asset and drilling portfolios closely, assessing value to the company and making changes where needed.

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In Colombia, we continued measures to contain the release of oil from a flow-through drainage chamber in the Mary battery and investigated the source of the release. We are developing a plan for remediation activities. Additionally, during 2013, the number of illegal valves installed on the section of pipeline from Uchupayaco to Santana increased. Three oil seeps were found which related to pipeline disruptions in areas with difficult access. In each of these incidents, we completed a full clean up and remediation of the affected area. A number of minor incidents on our blocks occurred, each of which caused small quantities of oil to be spilled. In each of these minor incidents, we completed a full clean up and remediation of the affected area.

•	In Argentina, minor spills occurred relating to oil and produced water transported by pipeline. In each case, we completed a full clean up and remediation of the affected area. We also undertook site remediation and restoration activities.

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In Peru, we continued the Environmental Monitoring Program for drilling and seismic activities on Block 95 and partnerships were established with the Pacaya Samiria Natural Reserve and Pucacuro National Reserve. We are also seeking the necessary permits for the relocation of four well pads and a new seismic project in Block 107 and we continued preparations for an Environmental Impact Study for seismic and drilling activities on Blocks 133, 123 and 129.

•	In Brazil, we implemented a water, soil and air monitoring program for our blocks in the Recôncavo Basin, constructed barriers on the Tiê field to prevent soil erosion and to contain minor spills and commenced a reforestation project.

•	Provided support for education, including providing funding for technology.

•	Supported community groups in projects that benefited local families with agriculture projects.

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•	Various projects for the support of cultural identity such as sponsorship of local festivals that celebrate indigenous culture and history and sponsorship of local people to attend a conference of indigenous peoples from various areas in the country.

•	Various programs for strengthening local infrastructure such as paving streets in urban areas, construction of cultural venues, construction of sport facilities and computer rooms, and provision of materials for electric power supply in rural areas.

•	Projects related to health, basic sanitation and housing including construction of a hospital emergency room and improving health facilities and housing.

•	Provided strong communications with the communities and undertook consultations with ethnic minorities.

•	Provided and distributed education materials to schools in our operated areas. Ran workshops and provided training to teachers for health, and physical education.

•	Provided child protection related training courses to local organizations.

•	Provided materials and support to local communities for improvements to rain water gathering systems.

•	Worked with a local agricultural agency to improve crop production, including providing tools, seeds and education.

•	Supported fair trade initiatives for local artisans.

•	Worked with local communities to improve chaguar production, a plant that is used to make fabrics, baskets and belts.

•	Supported local youth environmental protection initiatives.

•	Delivered supplies and medicines to hospitals.

•	On Block 95, we made improvements to the health center and electricity generators in Bretaña town.

•	Held consultation and education sessions with various communities located on our blocks and developed technical workshops with indigenous organizations on the uses of natural resources.

•	Provided healthcare support services to communities in our blocks.

•	Provided temporary employment to residents in our blocks.

•	Supported initiatives to provide identification documents to rural communities to enable them to work and access health, education and other social programs.

•	Provided funding for turtle conservation projects in the Pacaya Samiria National Reserve.

•	Supported conservation monitoring activities in the Pucacuro National Reserve, included financing the construction of a conservation research center.

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•	all bilateral aid, except anti-narcotics and humanitarian aid, would be suspended;

•	the Export-Import Bank of the United States and the Overseas Private Investment Corporation would not approve financing for new projects in Colombia;

•	United States representatives at multilateral lending institutions would be required to vote against all loan requests from Colombia, although such votes would not constitute vetoes; and

•	the President of the United States and Congress would retain the right to apply future trade sanctions.

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•	expand our systems effectively or efficiently or in a timely manner;

•	allocate our human resources optimally;

•	identify and hire qualified employees or retain valued employees; or

•	incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

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•	dilution caused by our issuance of additional shares of Common Stock and other forms of equity securities, which we expect to make in connection with acquisitions of other companies or assets;

•	announcements of new acquisitions, reserve discoveries or other business initiatives by our competitors;

•	fluctuations in revenue from our oil and natural gas business;

•	changes in the market and/or WTI or Brent price for oil and natural gas commodities and/or in the capital markets generally, or under our credit agreement;

•	changes in the demand for oil and natural gas, including changes resulting from the introduction or expansion of alternative fuels;

•	changes in the social, political and/or legal climate in the regions in which we will operate;

•	changes in the valuation of similarly situated companies, both in our industry and in other industries;

•	changes in analysts’ estimates affecting us, our competitors and/or our industry;

•	changes in the accounting methods used in or otherwise affecting our industry;

•	announcements of technological innovations or new products available to the oil and natural gas industry;

•	announcements by relevant governments pertaining to incentives for alternative energy development programs;

•	fluctuations in interest rates, exchange rates and the availability of capital in the capital markets; and

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•	significant sales of shares of our Common Stock, including sales by future investors in future offerings we expect to make to raise additional capital.

•	quarterly variations in our revenues and operating expenses; and

•	additions and departures of key personnel.

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For the year ended December 31, 2013, oil and gas production, NAR and adjusted for inventory changes, increased by 32% to 22,267 BOEPD compared with 2012. In Colombia, alternative transportation arrangements to minimize the impact of pipeline disruptions, production from new wells and a decrease in oil inventory had a positive impact on production in 2013. Production in 2013 was 75% from the Chaza Block in Colombia and 8% and 5% from the Puesto Morales and Surubi Blocks in Argentina, respectively.

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Estimated proved oil and NGL reserves, NAR, as of December 31, 2013, were 39.8 MMbbl, a 4% increase from the estimated proved reserves as at December 31, 2012. Proved reserves at December 31, 2013 were after 2013 oil and NGL production of 7.8 MMbbl NAR before inventory changes. The increase was primarily due to positive technical adjustments for the Costayaco field due to reservoir performance, additional development drilling in the Costayaco field and the appraisal drilling program in the Moqueta field. Reserves were also added for the Tiê field in the Recôncavo Basin, Brazil due to production performance. These reserve additions were offset by a decrease of 2.2 MMbbl in Argentina reserves, primarily related to the Puesto Morales field due to deferred investment and inconclusive waterflood results.

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Estimated probable and possible oil and NGL reserves, NAR, as of December 31, 2013, were 68.9 MMbbl and 63.7 MMbbl, respectively, compared with 14.8 MMbbl and 21.5 MMbbl as of December 31, 2012. Probable oil and NGL reserves, NAR, increased by 366% and possible oil and NGL reserves, NAR, increased by 197% compared with 2012. The increase was due primarily to the Bretaña oil discovery in Peru which resulted in 57.6 MMbbl of probable and 47.0 MMbbl of possible liquids reserves.

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Estimated proved gas reserves, NAR, as of December 31, 2013, were 13.5 Bcf compared with 12.8 Bcf as at December 31, 2012. At December 31, 2013, 59% of proved gas reserves were in the Sierra Nevada Block in Colombia and 35% were in the Puesto Morales Block in Argentina. Proved gas reserves were consistent with the prior year end as new gas reserves were developed to replace 2013 production. Estimated probable and possible gas reserves, NAR, as of December 31, 2013, were 5.5 Bcf and 50.3 Bcf, respectively, compared with 5.1 Bcf and 51.7 Bcf as of December 31, 2012.

•	For the year ended December 31, 2013, revenue and other income increased by 24% to $723.6 million compared with $585.2 million in 2012. The positive contribution from higher production levels was partially offset by lower realized prices. The average price realized per BOE decreased by 6% to $88.65 from $94.29 in 2012.

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Net income increased by 27% to $126.3 million, or $0.45 per share basic and $0.44 per share diluted, for the year ended December 31, 2013, compared with $99.7 million, or $0.35 per share basic and diluted, in 2012. In 2013, increased oil and natural gas sales and foreign exchange gains and lower G&A expenses were partially offset by increased operating, DD&A and income tax expenses and other loss and the absence of other gain recorded in 2012. DD&A expenses for the year ended December 31, 2013, included a $30.8 million ceiling test impairment loss in our Argentina cost center due to a decrease in reserves as a result of deferred investment and inconclusive waterflood results on the Puesto Morales Block. DD&A expenses in 2012 included a $20.2 million ceiling test impairment in our Brazil cost center related to seismic and drilling costs on Block BM-CAL-10.

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For the year ended December 31, 2013, funds flow from operations increased by 9% from $323.8 million to $352.9 million primarily due to increased oil and natural gas sales and lower G&A expenses and realized foreign exchange losses partially offset by increased operating and income tax expenses, including a $10.4 million non-recurring tax expense in Brazil on the proceeds from termination of a farmout agreement .

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Cash and cash equivalents were $428.8 million at December 31, 2013, compared with $212.6 million at December 31, 2012. The change in cash and cash equivalents during 2013 was primarily the result of funds flow from operations of $352.9 million, a $167.9 million change in net assets and liabilities from operating activities, proceeds from oil and gas properties of $59.6 million, and proceeds from issuance of common stock of $3.8 million, partially offset by capital expenditures of $367.3 million and a $0.8 million increase in restricted cash.

•	Working capital (including cash and cash equivalents) was $245.8 million at December 31, 2013, a $23.4 million increase from December 31, 2012.

•	Property, plant and equipment at December 31, 2013, was $1.3 billion, an increase of $54.7 million from December 31, 2012, as a result of $314.8 million of net capital expenditures (net of proceeds from oil and gas properties of $59.6 million and excluding changes in non-cash working capital), partially offset by $260.1 million of depletion, depreciation and impairment expenses.

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Net capital expenditures for the year ended December 31, 2013, were $314.8 million compared with $313.2 million for the year ended December 31, 2012. In 2013, capital expenditures included drilling of $220.9 million, geological and geophysical (“G&G”) expenditures of $93.0 million, facilities of $34.4 million and other expenditures of $26.1 million. Capital expenditures in 2013 were offset by proceeds from oil and gas properties of $59.6 million.

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(1)	Production represents production volumes NAR adjusted for inventory changes.

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•	On the Chaza Block (100% working interest ("WI"), operated), we drilled and completed the Moqueta-10 and -11 development wells in the Moqueta field and the Costayaco-18 development well in the Costayaco field as oil producers and commenced drilling the Moqueta-12 development well and the Zapotero-1 and Corunta-1 exploration

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•	We drilled one gross exploration well, Miraflor Oeste-1, on the Guayuyaco Block (70% WI, operated), which resulted in an oil discovery.

•	Together with our partner, we continued drilling the Mayalito-1P exploration well on the Llanos-22 Block (45% WI, non-operated) and this also resulted in an oil discovery.

•	We performed workovers on the Santana Block (35% WI, operated).

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We acquired 3-D seismic on the Garibay Block (50% WI, non-operated) and 2-D seismic on the Piedemonte Sur (100%, operated) and Magdalena Blocks (100% WI, operated). We started 3-D seismic on the Putumayo-1 Block (55% WI, operated) and 2-D seismic on the Cauca-7 Block (100% WI, operated) and Putumayo-10 (100% WI, operated) Blocks. We commenced G&G studies, including aeromagnetic surveys, on the Sinu-1 (60% WI, operated)and Sinu-3 Blocks (51% WI, operated). and seismic reprocessing and G&G studies on the Llanos-22 Block.

•	We also continued facilities work at the Costayaco and Moqueta fields on the Chaza Block, the Llanos-22 Block and the Guayuyaco Block.

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(1)	Production represents production volumes NAR adjusted for inventory changes.

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•	We drilled and completed two development wells, PMN-1130-SB and PMN-1131-SB, on the Puesto Morales Block (100% WI, operated). Both wells are on production.

•	We commenced drilling a horizontal multi-stage fracture stimulated well into the Loma Montosa formation on the Puesto Morales Block to further evaluate this new play. Work on this well is currently suspended due to landowner blockades that prevent safe operations. We also completed workovers on wells on the Puesto Morales Block.

•	We purchased materials in preparation for drilling a development well on the Surubi Block (85% WI, operated).

•	We acquired the remaining 50% working interest in the El Vinalar Block (100% WI, operated) from our partner.

•	We undertook facilities work at the Surubi and Puesto Morales Blocks.

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On Block 95 (100% WI, operated), we completed drilling a horizontal side-track extension of the Bretaña Norte 95-2-1XD exploration well. We also completed a preliminary Front End Engineering Design study for the Bretaña field development and completed a 2-D seismic program to provide a more detailed map of the Bretaña structure, along with maturing separate independent exploration leads on Block 95.

•	On Blocks 123, 129 and 107 (all 100% WI, operated), we continued work to obtain the necessary environmental and social permits for future seismic programs.

•	On Block 133 (100% WI, operated), we completed an aeromagnetic and aerogravity survey.

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(1)	Production represents production volumes NAR adjusted for inventory changes.

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•	On Block REC-T-155 , we drilled an exploration well, 1-GTE-8DP-BA and a horizontal sidetrack oil exploration well, 1-GTE-7HPC-BA, from the 1-GTE-7-BA wellbore. Both of these wells are currently suspended awaiting fracture stimulation. We also performed facilities work on Block 155.

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•	On Block REC-T-129 , we re-entered and isolated the final two fracture stages at the horizontal sidetrack oil exploration well, 1-GTE-6HP-BA.

•	Together with our partners, we relinquished our interest in Block BM-CAL-7 and paid a penalty of $1.3 million for not meeting the first exploration phase work obligation to drill a well on this block.

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•	no economic value is attributed to probable and possible reserves;

•	use of a 10% discount rate is arbitrary; and

•	prices change constantly from the twelve month period unweighted arithmetic average of the price as of the first day of each month within that twelve month period.

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