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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 the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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.

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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.

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.

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•	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.

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.

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•	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;

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in Peru, we continued engineering, procurement and construction work in preparation for a long-term production test, commenced drilling the Bretaña Sur 95-3-4-1X well, drilled the Bretaña Sur 95-2-1XD water disposal well and continued to purchase long-lead items for future drilling activities on the Bretaña field on Block 95. Subsequent to year-end, the Bretaña Sur appraisal well completed drilling operations and encountered an oil column less than what we had estimated prior to drilling. On Block 107, we commenced the acquisition of 2-D seismic and continued the refurbishment of a base camp; and

•	in Brazil, on Block REC-T-155 we successfully completed the dual completions of the 3-GTE-03-BA and 4-GTE-04-BA development wells in the Tiê field and completed a single stage fracture stimulation on the 1-GTE-8DP-BA exploration well, commenced the acquisition of 3-D seismic on Blocks REC-T-86, REC-T-117 and REC-T-118, and performed planning activities for future drilling activity.

•

3.4 million gross acres (2.8 million net) in Colombia covering 16 exploration and production contracts, five of which were producing and 15 of which were operated by Gran Tierra (excludes 0.9 million gross and net acres on four blocks where relinquishments were subject to approval and acreage changes, also subject to approval, on a further two blocks and includes 126,792 gross and 88,754 net acres on a block where the acquisition was subject to approval);

•	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

•	5.7 million gross acres (5.7 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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In Colombia, we received the Exploitation License for the Moqueta field, the amendment of the Environmental License for the Mocoa River Exploratory Drilling Area, the amendment of the Global License for the Costayaco field and the Environmental License for the Cabañas Exploratory Drilling Area. We started the in-situ bioremediation of contaminated soil in the Mary battery, which contamination is believed to have been the result of guerrilla activity that occurred in 1998. We commenced measures to control any oil leakage resulting from illegal valves installed on the section of pipeline from Uchupayaco to Sanata, removed the illegal valves and recovered the affected soil and bodies of water after the affected area was secured by the government. Contaminated material was transported to specialized companies with the necessary environmental licenses for treatment and disposal, in accordance with our policy. A number of other minor incidents within our facilities occurred, each of which caused small quantities of oil to be spilled. In each of these minor incidents, we completed a full clean up of the affected area.

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In Peru, we continued the Environmental Monitoring Program for drilling activities on Block 95 and started an Environmental Monitoring Program for seismic activities on Block 107. We continued partnerships with the Pacaya Samiria Natural Reserve, the Pucacuro National Reserve, the Forest Protection San Matías San Carlos (Block 107) and the Regional Conservation Area Pintuyacu Nanay Chambira & Pucacuro Natural Reserve (Blocks 123 and 129). We obtained the necessary permits for long-term test production and the relocation of a well pad on Block 95 and a seismic program in Block 107. We continue to work towards obtaining permits for drilling activities on Block 107 and exploration projects on Blocks 133, 123 and 129.

•	In Brazil, we implemented controls and field techniques to manage the social and environmental impact of seismic activities on our new exploration blocks in the Recôncavo Basin, completed work to improve the drainage system and constructed barriers on the Tiê field to contain minor spills and continued a reforestation project.

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•	Provided support for education, including providing funding for learning technology such as computers.

•	Supported community groups in projects that benefited local families with agriculture projects, including a widely recognized pepper production project with 58 formerly coca-growing families.

•	Sponsored a number of projects to strengthen cultural identity including local festivals that celebrate indigenous culture and history and costs for local delegates to attend a conference of indigenous peoples from various areas in the country.

•	Supported numerous programs for improving 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.

•	Implemented 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 focused consultations with ethnic minorities.

•	On Block 95, we made improvements to the Bretaña community health center and provided an electricity generator to the town.

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

•	Provided healthcare support services to communities and supported medical campaigns in our blocks.

•	Provided employment to residents in our blocks.

•	Implemented a community environmental monitoring program.

•	Provided 500 water filters to families in outlying communities.

•	Supported initiatives to provide national identification cards to undocumented people in remote rural communities to enable them to work and access health, education and other social programs.

•	Implemented a turtle conservation project in the Pacaya Samiria National Reserve.

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

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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.

•	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;

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•	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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•	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;

•	changes in independent reserve estimates related to our oil and gas properties;

•	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

•	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.

•	updated reserve estimates by independent parties.

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Oil and gas production NAR before inventory adjustments and losses increased to 19,283 BOEPD for the year ended December 31, 2014, compared with 19,071 BOEPD in 2013. In 2014, production from new wells in the Moqueta field in the Chaza Block and a new well in the Llanos-22 Block had a positive effect on production NAR before inventory adjustments and losses in Colombia, which was partially offset by the impact of well downtime for workovers and a water cut increase on the Costayaco field in the Chaza Block. Production in 2014 was 83% from the Chaza Block in Colombia.

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Oil and gas production, NAR and adjusted for inventory changes and losses, decreased by 4% to 18,523 BOEPD for the year ended December 31, 2014, compared with 19,239 BOEPD in 2013. During the year ended December 31, 2014, an oil inventory and losses ("oil inventory") increase accounted for 0.3 MMbbl or 760 bopd of reduced production compared with an oil inventory decrease in 2013 which accounted for 0.1 MMbbl or 168 bopd increased production.

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Estimated proved oil and NGL reserves, NAR, as of December 31, 2014, were 36.9 MMbbl, compared with 39.8 MMbbl as at December 31, 2013, and after 2014 oil and NGL production of 7.0 MMbbl NAR before inventory changes and losses, excluding Argentina production. The decrease was primarily due to the sale of our Argentina business unit during 2014 which contributed 3.6 MMbbl of proved oil and NGL reserves, NAR, as at December 31, 2013. This was partially offset by: reserve additions in Colombia for the Costayaco field due to reservoir performance and additional development

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Estimated probable and possible oil and NGL reserves, NAR, as of December 31, 2014, were 13.0 MMbbl and 14.9 MMbbl, respectively, compared with 68.9 MMbbl and 63.7 MMbbl as of December 31, 2013. As previously discussed, all probable and possible reserves associated with the Bretaña field on Block 95 in Peru were reclassified as contingent resources in a report with an effective date of January 31, 2015, as a result of the decision to cease all further development expenditures on the Bretaña field on Block 95 in Peru other than what is necessary to maintain tangible asset integrity and security. The December 31, 2014, reserves referred to in this bullet exclude probable and possible reserves associated with the Bretaña field. Estimated probable and possible oil and NGL reserves, NAR, as at December 31, 2013, included 1.8 and 2.6 MMbbl, respectively, in Argentina. The December 31, 2013, reserves also included 57.6 MMBOE and 104.7 MMBOE of 2P and 3P reserves relating to the Bretaña Field on Block 95 in Peru.

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Estimated proved gas reserves, NAR, as of December 31, 2014, were 1.0 Bcf compared with 13.5 Bcf at December 31, 2013. Estimated probable and possible gas reserves, NAR, as of December 31, 2014 were 3.4 Bcf and 2.5 Bcf, respectively, compared with 5.5 Bcf and 50.3 Bcf as of December 31, 2013. Estimated proved, probable and possible gas reserves in Argentina, NAR, as at December 31, 2013, were 4.7 Bcf, 1.7 Bcf and 46.2 Bcf, respectively.

•	For the year ended December 31, 2014, revenue and other income decreased by 13% to $562.3 million compared with $649.1 million in 2013. The decrease was due to the combined effect of decreased production and lower realized prices. The average price realized per BOE decreased by 10% to $82.74 from $92.13 in 2013.

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Loss from continuing operations for the year ended December 31, 2014, was $144.3 million, or $0.51 per share basic and diluted, compared with income from continuing operations of $181.0 million, or $0.64 per share basic and $0.63 per share diluted, in 2013. In the year ended December 31, 2014, we recorded an impairment loss of $265.1 million in our Peru cost center relating to costs incurred on Block 95.

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Loss from discontinued operations, net of income taxes, was $27.0 million, or $0.09 per share basic and diluted for the year ended December 31, 2014, compared with $54.7 million, or $0.19 per share basic and diluted, in 2013. Loss from discontinued operations after income taxes for the year ended December 31, 2013, included a ceiling test impairment loss of $30.8 million 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. For the year ended December 31, 2014, loss from discontinued operations, net of tax, included loss on disposal of the Argentina business unit of $19.3 million.

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Loss for the year ended December 31, 2014, was $171.3 million, or $0.60 per share basic and diluted, compared with net income of $126.3 million, or $0.45 per share basic and $0.44 per share diluted, in 2013. As previously discussed, in the year ended December 31, 2014, we recorded an impairment loss of $265.1 million in our Peru cost center relating to costs incurred on Block 95. Additionally, the decrease was due to lower income from continuing operations and the recognition of a loss on sale of the Argentina business unit, partially offset by the effect of the ceiling test impairment loss of $30.8 million in our Argentina cost center in 2013.

•	For the year ended December 31, 2014, funds flow from continuing operations decreased by 9% from $343.2 million to $311.3 million primarily due to decreased oil and natural gas sales and increased operating and G&A expenses, partially offset by realized foreign exchange and financial instrument gains and lower income tax expenses.

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Cash and cash equivalents were $331.8 million at December 31, 2014, compared with $428.8 million at December 31, 2013. The decrease in cash and cash equivalents for the year ended December 31, 2014, was primarily the result of cash capital expenditures of $347.0 million, cash used in operating activities of discontinued operations of $4.8 million and $97.9 million change in assets and liabilities from operating activities of continuing operations, partially offset by funds flow from continuing operations of $311.3 million, cash provided by investing activities of discontinued operations of $30.4 million, and proceeds from the issuance of shares of common stock of $11.1 million.

•	Working capital (including cash and cash equivalents) was $239.8 million at December 31, 2014, a $6.0 million decrease from December 31, 2013.

•	Property, plant and equipment ("PPE") at December 31, 2014, was $1.1 billion, a decrease of $131.2 million from December 31, 2013, as a result of $416.2 million of capital expenditures related to continuing operations and $18.7 million of capital expenditures related to discontinued operations, partially offset by the sale of the Argentina business unit PPE of

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•	Capital expenditures for the year ended December 31, 2014 for continuing operations, were $416.2 million compared with $295.3 million for the year ended December 31, 2013. In 2014, capital expenditures included drilling of $245.3 million, geological and geophysical (“G&G”) expenditures of $96.1 million, facilities of $36.6 million and other expenditures of $38.2 million.

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

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•	On the Chaza Block (100% working interest ("WI"), operated), we drilled and completed the Costayaco-20, Costayaco-21 and Costayaco-22 development wells in the Costayaco field and commenced drilling the Costayaco-19i

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•	We completed initial testing and evaluation of the Miraflor Oeste exploration well on the Guayuyaco Block (70% WI, operated). This oil well is currently on long-term test production.

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We acquired 2-D seismic and completed interpretation of the seismic data on the Piedemonte Sur Block (100%, operated), completed 3-D seismic on the Putumayo-1 Block (55% WI, operated) and 2-D seismic on the Cauca-7 Block (100% WI, operated), and commenced activities in preparation for the acquisition of 2-D seismic on the Putumayo-10 (100% WI, operated) Block. We continued G&G studies, including aeromagnetic surveys and completed the acquisition of 2-D seismic on the Sinu-1 (60% WI, operated) and Sinu-3 (51% WI, operated) Blocks. We completed regional field studies and continued work to obtain the necessary environmental and social permits for future seismic programs on the Chaza Block.

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

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On Block 95 (100% WI, operated), we drilled the Bretaña Sur 95-3-4-1X appraisal well on the L4 lobe on the Bretaña field, which satisfied our work obligation for the fifth exploration period. Subsequent to year-end, the Bretaña Sur appraisal well completed drilling operations and encountered approximately six feet of oil pay above the oil-water contact in the Vivian Sandstone Reservoir. This oil column is less than what we had estimated prior to drilling. We also drilled the Bretaña-1WD water disposal well, completed engineering and procurement and construction work in preparation for long-term production test and continued to purchase long-lead items for future drilling activities on this field. As previously discussed, in February 2015, we ceased all further development expenditures on the Bretaña field on Block 95 other than what is necessary to maintain tangible asset integrity and security.

•	On Block 107 (100% WI, operated), we commenced the acquisition of 2-D seismic and continued the refurbishment of a base camp. On Block 133 (100% WI, operated), we continued work to obtain the necessary environmental and social permits for future seismic programs.

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

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•	On Block REC-T-155 (100% WI, operated), we successfully completed the dual completions of the 3-GTE-03-BA and 4-GTE-04-BA development wells, completed a single stage fracture stimulation on the 1-GTE-8DP-BA exploration well, continued to evaluate alternatives for the 1-GTE-07HPC-BA exploration well and performed planning activities for future drilling activity.

•	On Blocks REC-T-86, REC-T-117 and REC-T-118 (100% WI, operated), we commenced the acquisition of 3-D seismic.

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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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