~~Proved oil and gas reserves.~~ ~~Proved oil and gas reserves are those quantities of oil and~~natural 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


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

(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.


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.~~	(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) 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.~~

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.~~


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.

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.

~~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)~~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 ~~reserves calculation is used in~~structurally higher portions of 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~~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 ~~data)~~conditions include prices and costs at which economic producibility from a reservoir is ~~used~~ to ~~generate a full range~~be determined. The price shall be the average price during the 12-month period prior to the ending date of ~~possible outcomes and their associated probabilities~~the period covered by the report, determined as an unweighted arithmetic average of ~~occurrences.~~

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.

~~Developed oil and gas reserves~~Proved undeveloped reserves.~~. Developed oil and gas~~ In general, 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. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.


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.

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.


~~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.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas regardless of whether such acreage contains proved reserves.

~~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.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production and requires the owner to pay a share of the costs of drilling and production operations.

PART I

~~Item 1.~~Items 1 and 2. Business and Properties

General

Gran Tierra Energy Inc. together with its subsidiaries (“Gran Tierra”, "us", "our", or “we”) is an independent international energy company engaged in oil and gas acquisition, exploration, development and production. We are strategically focused on onshore oil and gas properties in Colombia and also own the rights to oil and gas properties in ~~Colombia, Peru~~Brazil and ~~Brazil.~~

Peru. Our ~~principal executive offices are located~~Colombian properties represented 87% of our proved reserves NAR at ~~200, 150-13th Avenue S.W., Calgary, Alberta, Canada.~~December 31, 2015. The ~~telephone number at~~remainder of our ~~principal executive offices is (403) 265-3221. All dollar ($) amounts referred~~proved reserves were attributable to ~~in this Annual Report on Form 10-K are United States (U.S.) dollars, unless otherwise indicated.~~

~~Development of Our Business~~our Brazilian properties.

Our company was incorporated under the laws of the State of Nevada on June 6, 2003, originally under the name Goldstrike Inc. We ~~made our initial acquisition of oil and gas producing and non-producing properties in Argentina in September 2005. Since then, we~~ have acquired oil and gas producing and non-producing assets in Colombia, Peru, ~~Argentina~~ and Brazil, with our largest acquisitions being the ~~acquisition~~acquisitions of Argosy Energy International L.P. in 2006, Solana Resources Limited ~~(“Solana”)~~ in 2008 and Petrolifera Petroleum Limited ~~(“Petrolifera”)~~ in 2011.

~~On June 25, 2014, we, through several of our indirect subsidiaries, sold our Argentina business unit~~All dollar ($) amounts referred to ~~Madalena Energy Inc. ("Madalena"~~in this Annual Report on Form 10-K are United States (U.S.) ~~for aggregate consideration of $69.3 million, comprising $55.4 million in cash and $13.9 million in Madalena shares.~~dollars, unless otherwise indicated.

~~Largely~~2015 Overview

During early 2015, largely as a result of the ~~current~~ low commodity price environment and drilling results in Peru, we ~~reevaluated our business strategy with a renewed focus on balancing the return and risk of our exploration and development projects. As a result, on February 19, 2015, we made the decision to cease~~ceased all ~~further~~ development expenditures onin the Bretaña ~~field~~Field on Block 95 in Peru other than what is necessary to maintain tangible asset integrity and security. ~~The high capital investment, associated debt financing and long-term payout horizon of this project does not align with our shift in strategy as announced on February 2, 2015.~~

Considering the current low commodity price environment and the significant aspects of the Bretaña field project which were no longer in line with our strategy, our Board of Directors determined that they would not proceed with the further capital investment required to develop the Bretaña field. As a result, ~~of this decision,~~ all probable and possible reserves associated with the field were reclassified as contingent ~~resources~~resources.

On May 7, 2015, we entered into an agreement (the “Agreement”) with West Face SPV (Cayman) I L.P. (“West Face”) pursuant to which we settled a proxy contest. Pursuant to the terms of the Agreement, Gary Guidry was appointed as our President and Chief Executive Officer. Mr. Guidry replaced Duncan Nightingale in that role, who was serving as interim Chief Executive Officer since February 2015 and, with the appointment of Mr. Guidry as Chief Executive Officer, was designated as Executive Vice President. Additionally, effective May 11, 2015, Ryan Ellson was appointed as Chief Financial Officer. In connection with our entry into the Agreement, the size of our Board of Directors was expanded, new directors were appointed to fill the newly created vacancies and certain existing directors agreed not to stand for re-election at the 2015 annual meeting of stockholders. In June 2015, our Board of Directors approved a ~~report with~~new capital program focusing on development activities in Colombia.

On January 13, 2016, we acquired all of the issued and outstanding shares of Petroamerica Oil Corp ("Petroamerica") for cash consideration of $70.6 million and the issuance of 13,656,719 shares of Gran Tierra common stock. The net purchase price of Petroamerica was $70.4 million, after giving consideration to estimated net working capital of $26.0 million. On January 25, 2016, we acquired all of the issued and outstanding shares of PetroGranada Colombia Limited ("PGC"). The net purchase price of PGC was $19.0 million, after giving consideration to estimated net working capital of $18.7 million. In addition, we agreed to pay an ~~effective date~~additional $4.0 million if cumulative production from the Putumayo-7 Block plus gross proved plus probable reserves under the Putumayo-7 Block meet or exceed 8 MMbbl in any year prior to January 2021. Combined proved NAR oil and gas reserves of ~~January 31, 2015. Further~~Petroamerica and PGC as ~~a result, $265.1 million of unproved properties relating to Block 95 were impaired~~ at December 31, ~~2014. We expect to continue to identify and evaluate all options for~~2015, were 3.9 MMBOE calculated in compliance with the ~~Bretaña field.~~

~~In 2014:~~SEC rules.

~~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 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.2015 Operational Highlights

In the year ended December 31, ~~2014~~2015, we incurred capital expenditures of ~~$416.2~~$159.2 million, ~~(excluding changes~~including $87.7 million in ~~non-cash working capital).~~Colombia, $20.0 million in Brazil, $50.4 million in Peru and $1.1 million in Corporate. In ~~2014~~,the second half of 2015, after the change in management and substantial change of the board of directors, the majority of capital expenditures ~~included drilling expenditures of~~ ~~$245.3 million, geological and geophysical (“G&G”~~(86%) ~~expenditures of~~ ~~$96.1 million, facilities expenditures of~~ ~~$36.6 million~~ ~~and other expenditures of~~ ~~$38.3 million~~.were incurred in Colombia.

~~Our acreage as~~The significant elements of our ~~December 31, 2014~~2015~~, including acquisitions and excluding acres where relinquishments and acreage changes were subject to various government approvals, included:~~ capital program in Colombia were:

On the Chaza Block (100% working interest ("WI"), operated), we drilled and completed the Costayaco-25D and Costayaco-26D development wells in the Costayaco Field, and the Moqueta-17 and Moqueta-21D development wells in the Moqueta Field, as oil producers. The Moqueta-19i well was completed as a water injector as planned. We commenced drilling the Costayaco-24D and Costayaco-27i development well and started pre-drilling activities for the

~~3.4~~

Moqueta-20, 22 and 23 development wells. We also drilled the Moqueta-18i development well and encountered mechanical difficulties. This well is currently suspended.

On the Garibay Block (50% WI, non-operated) and Tiple Block (owned by two other parties), the unitization of the Jilguero Field was completed and we became a 38.5% WI owner in the newly unitized field. Together with our partners, we drilled and completed three development wells, Jilguero Sur-2, Jilguero-3 and Jilguero-4 as oil producing wells.

We completed the acquisition of 2-D seismic on the Cauca-7 (100% WI, operated), Sinu-1 (60% WI, operated) and Sinu-3 (51% WI, operated) Blocks and continued activities in preparation for the acquisition of 2-D seismic on the Putumayo-10 Block (100% WI, operated). We also commenced environmental impact assessments ("EIA"s) for future drilling on the Sinu-3 Block.

We also continued facilities work at the Costayaco and Moqueta Fields on the Chaza Block, and on the Jilguero unitized Field within the Garibay Block.

In Brazil:

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

On Block REC-T-155 (100% WI, operated), we initiated construction of an infield gas pipeline between the Tiê facilities and 3-GTE-03-BA.

In Peru:

On Block 95 (100% WI, operated), we completed drilling operations on the Bretaña Sur 95-3-4-1X appraisal well on the L4 lobe in the Bretaña Field, which satisfied our work obligation for the fifth exploration period. We encountered approximately six feet of oil pay above the oil-water contact in the Vivian Sandstone Reservoir. This oil column was less than what we had estimated prior to drilling. As previously discussed, in February 2015, we ceased all further development expenditures in the Bretaña Field on Block 95 other than what is necessary to maintain tangible asset integrity and security.

On Blocks 107 and 133 (100% WI, operated), we continued the environmental permitting process. On Block 107, we completed the acquisition, interpretation and processing of 2-D seismic and commenced planning activities for the Osheki-1 exploration well and the refurbishment of the base camp and well location. Both of these planning activities were suspended at the end of February 2015.

2016 Outlook

In January 2016, we announced our 2016 capital budget. Our base 2016 capital program of $107 million ~~gross acres (2.8~~consists of: $76 million ~~net)~~for Colombia; $8 million for Brazil; $6 million for Peru; and $17 million for other.

In Colombia, our base 2016 capital program includes two water injector wells in the Costayaco Field and three development wells in the Moqueta Field, both on the Chaza Block (100% WI, operated), two exploration wells and a development well in the Putumayo-7 Block (subject to regulatory approval, 100% WI, operated) and an exploration well on the Llanos-10 Block (50% WI, non-operated) with the costs being carried by a third party. Facilities work is also planned for the Chaza Block.

In Peru, the 2016 capital program includes only those activities required for retention of lands and security of assets. In Brazil, the capital program includes only minimal activity to implement water injection for reservoir pressure maintenance and to preserve current production levels. In both Peru and Brazil, operations have been scaled back significantly, with the aim of allowing time to explore and execute on options to maximize shareholder value.

In addition to our base 2016 capital budget, we have a discretionary capital budget of $61 million that we may utilize during 2016 in the event of an increase in commodity prices. If deployed, we expect that our discretionary capital budget would target six exploration wells, five development wells and seismic activities in Colombia.

We expect to finance our 2016 capital program through cash flows from operations and cash on hand, while retaining financial flexibility to undertake further development opportunities and opportunistically pursue acquisitions.

Business Strategy

The Company’s strategy is to efficiently grow and diversify its portfolio of exploration, development and production opportunities in Colombia. We are taking steps to maintain cash flows from existing assets, and seeking opportunities to leverage our financial strength to expand our Colombian operations and asset base.

Oil and Gas Properties

Colombia

On January 13, 2016, and January 25, 2016, respectively, we completed the acquisitions of all of the issued and outstanding shares of Petroamerica and PGC.

Excluding blocks subject to relinquishment, we have interests in 29 blocks in Colombia ~~covering~~and are the operator on 16 ~~exploration~~of these blocks, including 14 blocks acquired through the acquisitions of Petroamerica and ~~production contracts,~~ ~~five~~PGC (three operated). These blocks include interests in the Putumayo-7 Block for which assignment 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~~WI is subject to approval, ~~and acreage changes, also~~or final approval, by the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”). Relinquishments of our interests in four blocks in Colombia are subject to ~~approval,~~receipt of final documentation from the ANH. During 2015, unitization of the Jilguero Field on the Garibay and Tiple Block was completed and we became a ~~further two blocks~~38.5% WI owner in the newly unitized field, we executed an Exploration and ~~includes 126,792 gross~~Production Contract for the Putumayo-4 Block farm-in, received final documentation from the ANH for relinquishment of our interest in the Magangué Block, and ~~88,754 net acres~~our contract on ~~a block where~~ the ~~acquisition was subject to approval);~~Santana Block expired.

~~There were no sales in any countries other than Colombia, Brazil and Argentina in~~ ~~2014~~, ~~2013~~ or ~~2012~~.

See “Guerrilla Activity in Colombia Has Disrupted and Delayed, and Could Continue to Disrupt or Delay, Our Operations and We Are Concerned About Safeguarding Our Operations and Personnel in Colombia”, “Our Oil Sales Will Depend on a Relatively Small Group of Customers, Which Could Adversely Affect Our Financial Results,” and “Negative Political Developments in Peru May Negatively Affect our Proposed Operations,” “Our Business is Subject to Local Legal, Political and Economic Factors Which are Beyond Our Control, Which Could Impair Our Ability to Expand Our Operations or Operate Profitably” and other risk factors in Item 1A “Risk Factors” for a description of the risks faced by our dependency on a small number of customers and the regulatory systems under which we operate.

Competition

The oil and gas industry is highly competitive. We face competition from both local and international companies in acquiring properties, contracting for drilling and other oil field equipment and securing trained personnel. Many of these competitors, such as Ecopetrol, have financial and technical resources that exceed ~~ours and we believe that these companies have a competitive advantage in these areas.~~ours. Others are smaller and we believe our technical and financial capabilities give us a competitive advantage over these companies. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for prospects and resources in the oil and gas industry.

See “Competition in Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our Production May Impair Our Business” in Item 1A “Risk Factors” for risks associated with competition.

Geographic Information

Information regarding our geographic segments, including information on revenues, assets, expenses and net income, can be found in Note 54 to the Consolidated Financial Statements, Segment and Geographic Reporting, in Item 8 “Financial Statements and Supplementary Data”, which information is incorporated by reference here. Long lived assets are Property, Plant and Equipment, which includes all oil and gas assets, furniture and fixtures, automobiles and computer equipment. No long lived assets are held in our country of domicile, which is the United States of America. "All Other" assets include assets held by our corporate head office in Calgary, Alberta, Canada. Because all of our exploration and development operations are in South America, we face many risks associated with these operations. See Item 1A “Risk Factors” for risks associated with our foreign operations.

Regulation

The oil and gas industry in Colombia, Peru and Brazil is heavily regulated. Rights and obligations with regard to exploration, development and production activities are explicit for each project; economics are governed by a royalty/tax regime. Various government approvals are required for property acquisitions and transfers, including, but not limited to, meeting financial and technical qualification criteria in order to be certified as an oil and gas company in the country. Oil and gas concessions are typically granted for fixed terms with opportunity for extension.

Colombia

In Colombia, prior to 2004, Ecopetrol was the administrator of all hydrocarbons and therefore executed contracts with oil companies under different contractual types such as Association Contracts and Shared Risk Contracts. Under an Association Contract, the oil company (“Associate”) assumed all risk during the exploration phase and Ecopetrol had the obligation to reimburse the Associate, if the commerciality was accepted by Ecopetrol, the direct exploration costs which the Associate incurred in proportion to Ecopetrol's working interest. If Ecopetrol did not accept the initial commerciality of a field, the Associate could continue the activities at its sole risk and Ecopetrol would retain the right to back-in later, after Ecopetrol reimbursed the Associate for the initial exploitation work and exploration costs plus certain penalties, depending upon at what stage Ecopetrol later declared commerciality of the field.

Effective June 2003, the regulatory regime in Colombia underwent a significant change with the formation of the ANH. The ANH is now the administrator of the hydrocarbons in the country and therefore is responsible for regulating the Colombian oil and gas industry, including managing all exploration lands. Ecopetrol became a public company owned in majority by the state with the main purpose of exploring and producing hydrocarbons similar to any other oil company. However, Ecopetrol continues to have rights under the existing contracts executed with oil companies before the ANH was created. Ecopetrol continues to be the major purchaser and marketer of oil in Colombia and operates the majority of the oil transportation infrastructure in the country.

In conjunction with this change, the ANH developed a new exploration risk contract that took effect as of June 2004. This Exploration and Production Contract has significantly changed the way the industry views Colombia. In place of the earlier association contracts, the new agreement provides full risk/reward benefits for the contractor. Under the terms of the contract the successful operator retains the rights to all reserves, production and income from any new exploration block, subject to existing royalty and tax regulations. Each contract contains an exploration phase and a production phase. The exploration phase will contain a number of exploration periods and each period will have an associated work commitment. The production phase will last a number of years (usually 24) from the declaration of a commercial hydrocarbon discovery.

We operate in Colombia through ~~two~~the following branches –- Gran Tierra Energy Colombia Ltd. ~~and~~, Petrolifera Petroleum (Colombia) ~~Limited. Both~~Limited, Petroamerica International Colombia Corp. Sucursal, Petroamerica Energy Colombia Sucursal,

Petroamerica P&G Corp Colombia, Southeast Investment Corporation, Petroamerica Colombia, and PetroGranada Colombia Limited Sucursal Colombia. The home offices of Gran Tierra Energy Colombia Ltd., Petrolifera Petroleum (Colombia) Limited, Petroamerica Colombia and Petroamerica Energy Colombia Sucursal are qualified as operators of oil and gas properties by the ANH.

When operating under a contract, the contractor is the owner of the hydrocarbons extracted from the contract area during the performance of operations, except for royalty volumes which are collected by the ANH (or its designee), depending on the type of contract. The contractor can market the hydrocarbons in any manner whatsoever, subject to a limitation in the case of natural emergencies where the law specifies the manner of sale.

Peru

Peru’s hydrocarbon legislation, which includes the Organic Hydrocarbon Law No. 26221 enacted in 1993 and the regulations thereunder (the “Organic Hydrocarbon Law”), governs our operations in Peru. This legislation covers the entire range of petroleum operations, defines the roles of Peruvian government agencies which regulate and interact with the oil and gas

industry, provides that private investors (either national or foreign) may also make investments in the petroleum sector and provides for the promotion of the development of hydrocarbon activities based on free competition and free access to all economic activities. This law provides that pipeline transportation and natural gas distribution must be handled via concession contracts with the appropriate governmental authorities. All other petroleum activities are to be freely operated subject to complying with applicable regulation, including local safety and environment standards.

Under the Peruvian legal system, Peru is the owner of the hydrocarbons located below the surface in its national territory. However, Peru has given the ownership right to extracted hydrocarbons to PeruPetro S.A. ("PeruPetro"), a state company responsible for promoting and overseeing the investment of hydrocarbon exploration and exploitation activities in Peru. PeruPetro is empowered to enter into contracts for either the exploration and exploitation or just the exploitation of petroleum and natural gas on behalf of Peru, the nature of which are described further below. The Peruvian government also plays an active role in petroleum operations through various entities and agencies, including through the involvement of the Ministry of Energy and Mines(the specialized government department in charge of establishing energy, mining and environmental protection policies, enacting the rules applicable to all these sectors and supervising compliance with such policies and rules),OSINERGMIN (an agency in charge of checking compliance with hydrocarbon regulations) and OEFA (the entity of supervising environmental compliance). We are subject to the laws and regulations of all of these entities and agencies.

The Peruvian Constitution and the Organic Hydrocarbon Law states that a license contract does not provide for a transfer or lease of property over the area of the exploration or exploitation. In accordance with a license contract, a third party acquires the right to explore for or exploit hydrocarbons in a specified area and PeruPetro (the entity that holds the Peruvian state interest) transfers the property right in the extracted hydrocarbons to the third party, who must pay a royalty to the state.

PeruPetro enters into either license contracts or service contracts for hydrocarbon exploration and exploitation. Peruvian law also allows for other contract models, but the investor must propose contract terms compatible with Peru’s interests. We only operate under license contracts and do not foresee operating under any service contracts. License and service contracts are approved by supreme decree issued by the Peruvian Ministry of Economy and Finance and the Peruvian Ministry of Energy and Mining, and can only be modified by written agreement signed by the parties. A company must be qualified by PeruPetro to enter into negotiations for hydrocarbon exploration and exploitation contracts in Peru. In order to qualify, the company must meet the standards under the Regulations Governing the Qualifications of Oil Companies. These qualifications generally require the company to have the technical, legal, economic and financial capacity to comply with all obligations it will assume under the contract based on the characteristics of the area requested, the possible investments and the environmental protection rules governing the performance of its operations. When a contractor is a foreign investor, it is required to incorporate a subsidiary company or registered branch in accordance with Peruvian corporate law and appoint Peruvian representatives in accordance with the Organic Hydrocarbon Law who will interact with PeruPetro.

We operate in Peru through Gran Tierra Energy Peru S.R.L. and Petrolifera Petroleum del Peru ~~S.A.C.~~S.R.L. Gran Tierra Energy Peru S.R.L. has been qualified by PeruPetro with respect to its contracts for Blocks 95, 123 and 129 and Petrolifera has been qualified by PeruPetro with respect to its contracts for Blocks 107 and 133.

When operating under a license contract, the licensee is the owner of the hydrocarbons extracted from the contract area during the performance of operations and pays royalties which are collected by PeruPetro. The licensee can market or export the hydrocarbons in any manner whatsoever, subject to a limitation in the case of national emergency where the law stipulates such manner.

See “Negative Political Developments in Peru May Negatively Affect our Proposed Operations” in Item 1A “Risk Factors” for a description of the risks associated with the political climate in Peru.

Brazil

In Brazil, Law No. 2004 enacted in 1953 created the state monopoly of the petroleum industry and Petrobras, a state-owned legal entity, which was the sole company conducting exploration and production activities in Brazil. The Brazilian Federal Constitution enacted on October 5, 1988, continued this state monopoly of the petroleum industry.

Amendment No. 9 to the Brazilian Constitution, enacted on November 9, 1995, relaxed the state monopoly and authorized the Brazilian government to contract with state and private companies, with head offices and management located in Brazil, for the exploration and production of oil and natural gas, as well as to grant authorizations for the refining, transportation, import and export of oil, natural gas and its by-products.

The regulatory model is governed by Law No. 9478 of August 6, 1997 (the “Petroleum Law”), as amended, which controls the granting of concessions for carrying out exploration and production activities to Brazilian companies. The Petroleum Law, as amended, also established a legal framework for pre-salt layer areas and strategic areas to be defined by the Brazilian government and which will be subject to the Production Sharing Regime.

In accordance with the Petroleum Law, the acquisition of oil and natural gas property and oil and gas operations by state and private companies is subject to legal, technical and economic standards and regulations issued by the Agência Nacional de Petróleo, Gás Natural e Biocombustíveis ("ANP"), the agency created by the Petroleum Law and vested with regulatory and inspection authority to ensure adequate operational procedures with respect to industry activities and the supply of fuels throughout the national territory.

The ANP has authority for the implementation of the national oil and natural gas policy in accordance with the National Council of Energy Policy. The ANP conducts bid rounds to award exploration, development and production contracts, as well as to ~~approve~~authorize the construction and operation of refineries and gas processing units, transportation facilities (including port terminals), import and export of oil and natural gas, as well as supervision of the activities which integrate the petroleum industry and the general enforcement of the Petroleum Law.

During a public bid procedure, any company evidencing technical, financial and legal standards under the applicable bidding requirements may qualify and apply for particular blocks made available for concession contracts. Qualified companies may compete alone or in association with other companies, including through the formation of “consortia” (unincorporated joint-ventures), provided they agree to comply with all the applicable requirements of Brazilian Corporate Law. Blocks awarded and the duration of the exploration and production periods are defined in the contracts which, besides the usual covenants that can be found in oil concessions, such as exploration and development programs, relinquishment of areas, and unitization, include reversion to the state of certain assets at the end of the concession. Contracts may be assigned or transferred to other Brazilian companies that comply with the technical, financial and legal requirements established by the ANP.

Oil and natural gas resources in Brazil, whether onshore or offshore, belong to the Brazilian government. However, under the Concession Regime, after the discovery of oil and gas reserves, ownership is assigned to the concessionaire. Under the principles of the Federal Constitution, the national territory comprises all land and the continental shelf. Brazil is a signatory of the conventions regulating the economic use of the sea and its subsoil. Brazil is thus entitled to the enjoyment of the resources over the territorial sea and marine platform up to the limits indicated in the pertinent treaties.

Concessionaires are required under Law No. ~~9478/~~9,478/97 to pay the government dues and fees, in addition to the charges for sale of pre-bid data and information. The ANP has the power to determine the criteria under which the Government Take will be assessed within the limits established by Federal Decree No. ~~2705/~~2,705/98. Government Take comprises (i) signature bonus, (ii) royalties, (iii) special participation and (iv) area rentals. Part of the Government Take is passed on to States and Municipalities and other government branches according to law.

We operate in Brazil through Gran Tierra Energy Brasil Ltda. (“Gran Tierra Brazil”). Gran Tierra Brazil received approval from the ANP as a Class B operator permitting Grant Tierra Brazil to act as an operator both onshore and in the shallow water offshore Brazil.

In addition to the risk factors referenced in the Peru section above, see "Our Business is Subject to Local Legal, Political and Economic Factors Which are Beyond Our Control, Which Could Impair Our Ability to Expand Our Operations or Operate Profitably" in Item 1A “Risk Factors” for information regarding the regulatory risks that we face.

Environmental Compliance

Our activities are subject to existing laws and regulations governing environmental quality and pollution control in the countries where we maintain operations. Our activities with respect to exploration, drilling, production and facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil and other products, are subject to stringent environmental regulation by local, provincial, state and federal authorities in Colombia,

Peru and Brazil. Such regulations relate to environmental impact studies, ~~permissible levels~~the discharge of pollutants into air and water, ~~emissions, control~~management of hazardous waste, including its transportation, storage, and disposal, permitting for the construction of facilities, recycling requirements and reclamation standards, and the protection of certain plants and animal species, among others. Risks are inherent in oil and gas exploration, development and production operations, such as blowouts, fires, or spills, and significant costs and liabilities may be incurred in connection with environmental compliance issues. Licenses and permits ~~which we may require to carry out~~required for our exploration and production activities may not be obtainable on reasonable terms or on a timely basis, which could result in delays and ~~such laws and regulations may~~ have an adverse effect on ~~any project that we may wish to undertake.~~

In ~~2015, we plan to spend approximately $4.3 million~~our operations. Spills and releases into the environment of petroleum products can result in ~~Colombia on capital programs related to environmental studies, community consultations~~investigatory and environmental remediation. In Peru, costs for environmental and social projects are expected to be approximately $5.1 million and mainly relate to environmental and social impact assessments, implementationremedial liabilities. Moreover, violations of environmental ~~management plans~~laws and ~~environmental and social monitoring activities. In Brazil, we plan to spend approximately $1.3 million on costs for environmental projects including waste management.~~

In ~~2014, the following environmental activities occurred:~~

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 soilregulations can result in the ~~Mary battery,~~issuance of administrative, civil, or criminal fines and penalties, as well as orders or injunctions prohibiting some or all of our operations in affected areas. In addition, indigenous groups or other local organizations could oppose our operations in their communities, potentially resulting in delays 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 withcould adversely affect 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.

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.operations.

We plan to continue to strive to be in compliance with all environmental and pollution control laws and regulations in Colombia, Peru and Brazil. We plan to continue HSE initiatives in order to minimize our environmental impact and expenses. We also plan to continue to improve internal audit procedures and practices in order to monitor current performance and search for improvement.

Wedo not expect that the cost of compliance with local, provincial, state and federal provisions which have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment ~~for the remainder of our operations,~~ will ~~not~~ be material to us.

We have implemented a company wide web-based reporting system which allows us to better track incidents and respective corrective actions and associated costs. We have a Corporate ~~HSE~~Health, Safety, and Environmental Management System and follow ~~Environmental Best Practices.~~environmental best practices. We have also implemented an environmental risk management program in place as well as waste management procedures. Air and water testing occur regularly and environmental contingency plans have been prepared for all sites and ground transportation of oil. We have a regular quarterly comprehensive reporting system with a schedule of internal audits and routine checking of practices and procedures. Emergency response exercises were conducted in Colombia, Peru and Brazil.

~~Community Relations Initiatives~~

In ~~2014~~, However, despite these measures, we continued standardized quarterly reporting on our community relations initiatives. We prioritize hiring local people and companies in all our operations. In support of sustainable development, we have a program of community investment in all of our operating areas. These investments are based on local needs as evidenced in socio-economic baseline studies and consultation with the communities and government authorities socannot guarantee that our ~~investments meet their requirements~~operations will always be able to maintain compliance with applicable environmental laws and have the highest positive impact possible. We also continuously monitor the concerns and expectations of the communities where we operate to ensure our plans and activities are carried out in a manner that takes into account the communities’ needs and compensates and mitigates any possible adverse impacts.

~~Projects undertaken in~~ ~~2014~~ ~~were as follows:~~

~~Colombia~~

In ~~2014, our most significant community relations initiatives and investments were made~~regulations in the ~~municipalities of Mocoa, Villagarzon and Puerto Guzman in the Department of Putumayo and the Municipality of Piamonte in the Department of Cauca.~~

We made voluntary investments in relation to community support during drilling projects on the Chaza Block. Below is a description of our $2.5 million voluntary social investment, responding to the needs identified and prioritized by the communities in those areascountries in which we operate.

~~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.~~

~~Peru~~

In ~~2014, we invested approximately $2.0 million in the following activities:~~

~~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.~~

~~Brazil~~

In 2014, we invested approximately $80,000 in supporting schools in the municipality of Pojuca, in the Salvador region, including the “Prosa da minha terra” book creation project, benefiting 250 children, promoting literacy, creativity and self-esteem.

Employees

At December 31, ~~2014~~2015, we had ~~473~~301 full-time ~~employees:~~employees (December 31, 2014 - 473): 5258 located in the Calgary corporate office, ~~291~~193 in Colombia (~~150~~101 staff in Bogota and ~~141~~92 field personnel), 8828 in Peru ~~(71~~(19 office staff in Lima and 179 field staff) and 4222 in Brazil (309 office staff in Rio de Janeiro and Salvador and 1213 field staff). None of our employees are represented by labor unions and we consider our employee relations to be good.

Available Information

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to such reports and all other filings pursuant to Section 13(a) or 15(d) of the Exchange Act which we make available as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC, are available free of charge to the public on our website www.grantierra.com. ~~To access our SEC filings, select SEC Filings from the investor relations menu on our website, which will provide a list of our SEC filings.~~ Our website address is provided solely for informational purposes. We do not intend, by this reference, that our website should be deemed to be part of this Annual Report.

In addition, the SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding us. Any materials we have filed with the SEC may be read ~~and/~~or copied at the SEC’s Public Reference Room at 100 F Street N.E. Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding us. Our SEC filings are also available to the public at the SEC’s website at www.SEC.gov.

Item 1A. Risk Factors

Risks Related to Our Business

Guerrilla Activity in Colombia Has Disrupted and Delayed, and Could Continue to Disrupt or Delay, Our Operations and We ~~Are Concerned About Safeguarding~~May Be Unable to Safeguard Our Operations and Personnel in Colombia.

During 2012 and 2013, guerrilla activity in Colombia increased significantly, and the activity level remained high in 2014 and ~~into 2015 to date.~~2015. This increased activity creates a greater risk for our operations and our ~~employees and our mitigation activities may not be adequate to alleviate the risks arising from such guerrilla activity.~~employees.

For over 40 years, the Colombian government has been engaged in a conflict with two main Marxist guerrilla groups: the Revolutionary Armed Forces of Colombia ("FARC") and the National Liberation Army ("ELN"). Both of these groups have been designated as terrorist organizations by the United States and the European Union. Another threat comes from criminal gangs

formed from the former members of the United Self-Defense Forces of Colombia militia, a paramilitary group that originally sprouted up to combat FARC and ELN, which the Colombian government successfully dissolved.

Negotiations between the government and FARC may lead to a peaceful resolution and may not generate the intended outcome for either party. The impact of these negotiations, or any potential resolution, is not determinable on our operations.

We operate principally in the Putumayo Basin in Colombia, and have properties in other basins, including the Catatumbo, Cauca, Llanos, Sinu-San Jacinto, Middle Magdalena and Lower Magdalena Basins. ~~The Putumayo and Catatumbo regions have been the breeding place of guerrilla activity.~~ Pipelines have been primary targets of guerrillaactivity, because such pipelines cannot be adequately secured due to the sheer length of such pipelines and the remoteness of the areas in which the pipelines are laid. The ~~Ecopetrol-operated~~CENIT S.A ("CENIT")-operated Trans-Andean oil pipeline (the "OTA pipeline”), which transports oil from the Putumayo region to the Port of Tumaco and ~~upon~~ which ~~we materially rely~~is one of our export routes, has been targeted by ~~these guerrilla groups.~~FARC. Starting in 2008, the OTA pipeline experienced outages of various lengths. InSince 2012, the OTA pipeline ~~was shutdown~~has been shut down for ~~over 162~~784 days and the shutdown had a material adverse effect on our deliveries to Ecopetrol and our financial performance for 2012. Recently we have experienced outages from October 2012 through to January 2015. In 2013, the OTA pipeline was shutdown for approximately 229 days. In 2014, the OTA pipeline was shutdown for approximately 180 days, which included 49(including 166 days as a result of ~~a landslide. We have employed mitigation strategies as discussed in the risk "We May Encounter Difficulties Storing~~landslides and ~~Transporting Our Production, Which Could Cause a Decrease in Our Production or an Increase in Our Expenses"~~ ~~later in this section.~~maintenance works). Such disruptions may continue indefinitely and could harm our business.

In 2013, we experienced damage to two of our facilities in the amount of approximately $0.8 million. Production of about 330 bopd was shut in for 39 days. No long-term environmental damage or injury to personnel occurred in either incident. Continuing attempts by the Colombian government to reduce or prevent guerrilla activity may not be successful and dissident guerrilla activity may continue to disrupt our operations in the future. Our efforts to increase security measures may not be successful and there can also be no assurance that we can maintain the safety of our or our contractors' field personnel and Bogota head office personnel or operations in Colombia or that this violence will not continue to adversely affect our operations in the future and cause significant loss.

32We Are Vulnerable to Risks Associated with Geographically Concentrated Operations.

~~Our Lack of Diversification Will Increase the Risk of an Investment in Our Common Stock.~~

Our ~~business focuses on the oil and gas industry in a limited number of~~producing properties are geographically concentrated in Colombia, ~~Peru,~~ and ~~Brazil. Most~~as at December 31, 2015, 87% of our ~~production is in one basin~~proved reserves were located in Colombia. As a result of this concentration, we ~~lack diversification, in terms~~may be disproportionately exposed to the impact of, ~~both the nature~~among other things, regional supply and ~~geographic scope~~demand factors, delays or interruptions of our business. Accordingly, factors affecting our industry, such as the price of oil, or the regions in which we operate, including the geographic remoteness of our operations and weather conditions, will likely impact us more acutely than if our business was more diversified. In particular, most of our production is from two fields in the Putumayo Basin in Colombia, and we depend on the OTA pipeline and alternative transportation arrangements to transport our oil to market. Cash flow from these sales funds a large part of our business. Disruptions to this pipeline, as described in the risk "We May Encounter Difficulties Storing and Transporting Our Production, Which Could Cause a Decrease in Our Production or an Increase in Our Expenses", or decline in production from ~~these fields because of the natural aging cycle of the reservoir could harm our business~~wells in ~~Colombia and other countries.~~this area caused by governmental regulation or guerilla activities, transportation constraints or market limitations.

~~We Have an Aggressive Business Plan, and if~~If We do Not Have the Resources to Execute on Our Business Plan, We May Be Required to Curtail Our Operations.

Our ~~revised preliminary~~base capital program for ~~2015 calls for approximately $140~~2016 is $107 million to fund our exploration and development, which we intend to fund through cash flows from operations and cash on hand. Funding this program relies in part on oil prices remaining close to current levels or higher and other factors to generate sufficient cash flow. In addition to our base 2016 capital program we have a discretionary capital program of $61 million that we may utilize during 2016 if oil prices strengthen during the year. Oil prices were very volatile ~~at the end of~~in 2014 and 2015 and have remained at low levels in the first part of ~~2015. We have restricted activity and lowered our planned capital spending for 2015.~~2016. Low oil prices affect our debt capacity and the amount of money we can borrow using our oil reserves as collateral, as well as the amount of cash we are able to generate from ~~current~~ operations. If wecash flows from operations are not ~~able to generate the sales which, together with our current cash resources, are~~ sufficient to fund our capital program, we ~~will~~may not be able to ~~efficiently~~ execute our business plan which would cause us to further decrease our exploration and development, which could harm our business outlook, investor confidence and our share price.

We May Encounter Difficulties Storing and Transporting Our Production, Which Could Cause a Decrease in Our Production or an Increase in Our Expenses.

To sell the oil and natural gas that we are able to produce, we have to make arrangements for storage and distribution to the market. We rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. In certain areas, we may be required to rely on only one gathering system, trucking company or pipeline, and, if so, our ability to market our production would be subject to their reliability and operations. These factors may affect our ability to explore and develop properties and to store and transport our oil and gas production, and may increase our expenses. Furthermore, future instability in one or more of the countries in which we operate, weather conditions or natural disasters, actions by companies doing business in those countries, labor disputes or actions taken by the international community may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

The majority of our oil in Colombia is ~~contracted for delivery to a single~~shipped through the OTA pipeline owned by CENIT ~~S.A. ("CENIT"), a wholly-owned subsidiary of Ecopetrol,~~ and operated by Ecopetrol. Sales of oil have been and could continue to be disrupted by damage to this pipeline or displaced by Ecopetrol’s use of the pipeline itself. In addition, CENIT has a monopoly over pipeline transportation from the area and Ecopetrol over the operation of the port of Tumaco, which limits our ability to negotiate onproposed pipeline and port tariff increases and our costs may increase as a

result. Under our transportation contract with CENIT, the delivery point for our oil is at the end of ~~the~~this pipeline. This creates a risk of loss of oil due to sabotage by guerrillas or theft from the pipeline which may result in reduced revenues and increased clean-up or third party costs. ~~We have attempted to mitigate the risk of increased costs with insurance and are investigating potential ways to mitigate and reduce revenue risk.~~ CENIT and Ecopetrol maintain responsibility for clean-up of any spilled oil and for pipeline repair.

~~Problems with~~If these pipelines ~~can cause interruptions to our producing activities if they are~~remain down for ~~a long enough duration that~~extended periods of time, our storage facilities may become ~~full. For example, we experienced disruptions in transportation on this pipeline in March and April of 2008, June, July and August of 2009, June, August, and September 2010, February 2011, February~~full, which may cause us to ~~August of 2012 and October 2012 to January 2015, as a result of sabotage by guerrillas.~~limit producing activities. In addition, there is competition for space in these pipelines, and additional discoveries in our area of operations by other companies could decrease the pipeline capacity available to us. Trucking is an alternative to transportation by pipeline; however, it is generally more expensive and carries higher safety risks for us, our employees and the public.

~~Alternative~~Significant percentages of our 2014 and 2015 production were transported by alternative means. These alternatives are more expensive and reduce our average realized prices. In addition, these alternative means of transportation arrangements in Colombia allowed us to deliver our full production during 2013 and the first nine months of 2014; however, these deliveries result in reduced realized prices compared to the Ecopetrol operated OTA pipeline deliveries and aremay not ~~necessarily sustainable.~~be sustainable long term. When disruptions are of a long enough duration, our sales volumes may be lower than normal, which will cause our cash flow to be lower than normal, and if our storage facilities become full, we can be forced to reduce production.

We May Be Unable to Obtain Additional Capital That We Will Require to Implement Our Business Plan, Which Could Restrict Our Ability to Grow.

In ~~Peru, any oil produced~~the event that our cash flow from existing operations and cash on hand is not sufficient, we may require additional capital to fund our currently planned activities or to expand our exploration and development programs to additional properties. We may be ~~delivered via river barge. Suppliers of barges that meet our high standards for safety and reliability are limited and this may affect our ability~~unable to ~~deliver the production volumes we have planned for the test.~~obtain additional capital on favorable terms or at all.

~~Our Oil Sales Will Depend~~If we require additional capital, we may pursue sources of capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be able to access capital on favorable terms or at all. If we do succeed in raising additional capital, future financings may be dilutive to our shareholders, as we could issue additional shares of Common Stock or other equity to investors. In addition, debt and other mezzanine financing may involve a ~~Relatively Small Group~~pledge of ~~Customers, Which Could Adversely Affect Our Financial Results.~~

~~During the year ended December 31, 2014,~~assets and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we ~~sold to Ecopetrol, one other main customer~~may issue, such as convertibles and three other customers. While oil prices in Colombia are related to international market prices, lack of competition and reliance on a limited number of customers for sales of oil may diminish prices and depresswarrants, which will adversely impact our financial results.

~~In Brazil, there are a number~~Our ability to obtain needed financing may be impaired by factors such as the capital markets (both generally and for the oil and gas industry in particular), the location of ~~potential customers for~~ our oil and natural gas properties in South America, prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us), and the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. The price of oil and natural gas also effects the value of our oil and natural gas reserves, which dictates our capacity to borrow using those reserves as collateral. Some of the contractual arrangements governing our exploration activity may require us to commit to certain capital expenditures, and we may lose our contract rights if we do not have the required capital to fulfill these commitments. If the amount of capital we are ~~working~~able to ~~establish relationships~~raise from financing activities, together with our cash flow from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our activities), we may be required to curtail our operations.

The Borrowing Base Under Our Revolving Credit Facility May Be Reduced in Light of Recent Commodity Price Declines, Which Could Hinder or Prevent us From Meeting Our Future Capital Needs.

The borrowing base under our revolving credit facility is currently $200 million, and lender commitments under our revolving credit facility are $500 million. Our borrowing base is redetermined by the lenders twice per year, and the next scheduled borrowing base redetermination is in May 2016. Our borrowing base may decrease as ~~many~~a result of current oil and natural gas price levels, a further decline in oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for any other reason. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. In the event of a decrease in our borrowing base due to current or further declines in commodity prices or otherwise, we may be unable to meet our obligations as ~~possible~~they come due and could be required to ~~ensure~~repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital market to meet our obligations. As a ~~stable market for~~result, we may be unable to implement our ~~oil. Currently, almost all~~drilling and development plan, make acquisitions or otherwise carry out our business plan, which would have a material adverse effect on our financial condition and results of ~~our production in Brazil is sold to Petróleo Brasileiro S.A (“Petrobras”). Petrobras’ refinery in the area of our~~ operations ~~has previously had some technical difficulties which have restricted its~~and impair our ability to ~~receive deliveries. This could mean that we cannot produce to full capacity in the area because of restrictions in being able to deliver~~service our ~~oil.~~indebtedness.

Our Business is Subject to Local Legal, Political and Economic Factors Which Are Beyond Our Control, Which Could Impair Our Ability to Expand Our Operations or Operate Profitably.

We operate our business in Colombia, Peru, and Brazil, and may eventually expand to other countries. Exploration and production operations in foreign countries are subject to legal, political and economic uncertainties, including terrorism, military repression, social unrest, strikes by local or national labor groups, interference with private contract rights (such as nationalization), extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. Our production in Brazil was shut in for three weeks in October 2013 as a result of a strike by employees of Petrobras which affected the crude oil receiving terminal we use in the Recôncavo Basin, and we ~~have~~ experienced minor delays in trucking operations due to demonstrations and strikes in our operating area during the year ended December 31, ~~2014.~~2014 and 2015. We do not know how long any such labor action will last, and if it lasts a significant amount of time, it may affect our ability to meet our production targets.

South America has a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including the imposition of additional taxes. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. Any changes in oil and gas or investment regulations and policies or a shift in political attitudes in Colombia, Peru or Brazil or other countries in which we intend to operate are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.

Changes in laws in the jurisdiction in which we operate or expand into with the effect of favoring local enterprises, and changes in political views regarding the exploitation and protection of natural resources and economic pressures, may make it more difficult for us to negotiate agreements on favorable terms, obtain required licenses, comply with regulations or effectively adapt to adverse economic changes, such as increased taxes, higher costs, inflationary pressure and currency fluctuations. In certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These licenses and agreements may be susceptible to revision or cancellation and legal redress may be uncertain or delayed.

Recently, in the Department of Putumayo in Colombia where we operate, despite a company’s compliance with legislative requirements for prior consultation of communities and minority ethnic groups and the receipt of the necessary permits to drill and operate, new ethnic groups have been threatening, and in some cases using, the Judicial Branch of the Government, Superior Court of the Judicial District of Mocoa (the “Local Court”) to require that they be consulted, and thereby obtain benefits from companies operating in the Department of Putumayo as a result of those consultations. The Local Court has the ultimate jurisdiction to determine, upon a writ for protection or tutela, by an ethnic group (i) whether there has been a violation of a fundamental right to prior consultation by act or omission of a public authority or individual and (ii) whether the ethnic

group is legitimate. If the Local Court determines that there has been a violation and the ethnic group is legitimate despite receipt by the company of its proper governmental permits, the Local Court has the power to invalidate a company’s permits and force the company to cease operations immediately until such time as the company can successfully appeal to the Supreme Court to overturn the Local Court’s decision or prior consultations are completed and the permits effective once again.

Property right transfers, joint ventures, licenses, license applications or other legal arrangements pursuant to which we operate may be adversely affected by the actions of government and judicial authorities and the effectiveness of and enforcement of our rights under such arrangements in these jurisdictions may be impaired and, if we are faced with a tutela, our operations in the area(s) governed by a Local Court’s order may be shut down for a period of time thereby causing significant harm to our business in Colombia.

Recently in Brazil, environmental regulations related to fracture stimulation drilling have been under review by national agencies. In December 2014, the ~~ANP~~Agência Nacional de Petróleo Gás Natural e Biocombustíveis ("ANP") issued an injunction specifically related to properties in the Recôncavo Basin covered by Bid Round 12. This injunction placed a moratorium on unconventional activities on the Bid Round 12 blocks, all of which were unconventional exploration targets, until such a time as policies governing unconventional activities are finalized. Blocks REC-T-129, REC-T-142, REC-T-155 and REC-T-224 were granted in Bid Round 9, for which there has not been a similar injunction; however, we expect that the ANP’s injunction may limit our ability to receive permits in the short-term for our blocks with unconventional exploration targets. We acquired Blocks REC-T-86, REC-T-117 and REC-T-118 in Bid Round 11 and these blocks may be affected by the same or a similar injunction as the one placed on blocks acquired in Bid Round 12. Until this situation is resolved, the expansion of our drilling operations in Brazil may be limited which would harm our business in Brazil.

Pending regulations related to emissions and the impact of any changes in climate could adversely impact our business.

Governments around the world have become increasingly focused on regulating greenhouse gas ("GHG") emissions and addressing the impacts of climate change in some manner. Brazil, Peru and Colombia all have enacted legislation related to GHG emissions. For example, in July 2015, Colombia announced that it will seek to reduce the national emission of greenhouse gases by at least 20% over the next 15 years. Colombia has also passed legislation requiring the country to generate 77% of its energy from renewable resources and reduce deforestation in the Amazon to zero by 2020. Peru and Brazil have passed similar climate change-related measures.

GHG emissions legislation is emerging and is subject to change. For example, on an international level, almost 200 nations agreed on December 12, 2015, to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that we produce.

Current GHG emissions legislation has not resulted in material compliance costs, however, it is not possible at this time to predict whether proposed legislation or regulations will be adopted, and any such future laws and regulations could result in additional compliance costs or additional operating restrictions. If we are unable to recover a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Further, to the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of or access to capital.

Almost All of Our Cash and Cash Equivalents is Held Outside of Canada and the United States, and if We Determine to, or Are Required to, Repatriate These Funds, We Could Be Subject to ~~Significant~~ Taxes.

At December 31, ~~2014, 87%~~2015, 92% of our cash and cash equivalents was held by subsidiaries and partnerships outside of Canada and the United States. This cash is generally not available to fund domestic or head office operations unless funds are repatriated. At this time, we do not intend to repatriate funds, but if we did, we might have to accrue and pay taxes in certain jurisdictions on the distribution of accumulated earnings.

Strategic and Business Relationships Upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.

Our ability to successfully bid on and acquire additional properties, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements will depend on developing and maintaining effective working relationships with industry participants and on our ability to select and evaluate suitable partners and to consummate transactions in a highly competitive environment. These relationships are subject to change and may impair our ability to grow.

To develop our business, we enter into strategic and business relationships, which may take the form of joint ventures with other parties or with local government bodies, or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We also have an active business development program to develop those relationships and foster new relationships. We may not be able to establish these business relationships, or if established, we may choose the wrong partner or we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to take to fulfill our obligations to these partners or maintain our relationships. If we fail to make the cash calls required by our joint venture partners in the joint ventures we do not operate, we may be required to forfeit our interests in these joint ventures. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

In cases where we are the operator, our partners may not be able to fulfill their obligations, which would require us to either take on their obligations in addition to our own, or possibly forfeit our rights to the area involved in the joint venture. In addition, despite our partner’s failure to fulfill its obligations, if we elect to terminate such relationship, we may be involved in litigation with such partners or may be required to pay amounts in settlement to avoid litigation despite such partner’s failure to perform. Alternatively, our partners may be able to fulfill their obligations, but will not agree with our proposals as operator of the property. In this case there could be disagreements between joint venture partners that could be costly in terms of dollars, time, deterioration of the partner relationship, and/or our reputation as a reputable operator. These joint venture partners may not comply with their responsibilities or may engage in conduct that could result in liability to us.

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In cases where we are not the operator of the joint venture, the success of the projects held under these joint ventures is substantially dependent on our joint venture partners. The operator is responsible for day-to-day operations, safety, environmental compliance and relationships with government and vendors.

We have various work obligations on our blocks that must be fulfilled or we could face penalties, or lose our rights to those blocks if we do not fulfill our work obligations. Failure to fulfill obligations in one block can also have implications on the ability to operate other blocks in the country ranging from delays in government process and procedure to loss of rights in other blocks or in the country as a whole. Failure to meet obligations in one particular country may also have an impact on our ability to operate in others.

Disputes or Uncertainties May Arise in Relation to Our Royalty Obligations

Our production is subject to royalty obligations which may be prescribed by government regulation or by contract. These royalty obligations may be subject to changes in interpretation as business circumstances change.

As discussed in Note 1211 to the Consolidated Financial Statements in Part II, Item 8 below, our production from the Costayaco Exploitation Area is subject to the HPR royalty, which applies when cumulative gross production from an Exploitation Area is greater than five MMbbl. The HPR royalty is calculated on the difference between a trigger price defined in the Chaza Contract and the sales price. The ANH has interpreted the Chaza Contract as requiring that the HPR royalty must be paid with respect to all production from the Moqueta Exploitation Area and initiated a noncompliance procedure under the Chaza Contract, which we contested because the Moqueta Exploitation Area and the Costayaco Exploitation Area are separate Exploitation Areas. ANH did not proceed with that noncompliance procedure. We also believe that the evidence shows that the Costayaco and Moqueta ~~fields~~Fields are two clearly separate and independent hydrocarbon accumulations. Therefore, it is our view that, pursuant to the terms of the Chaza Contract, the HPR royalty is only to be paid with respect to production from the Moqueta Exploitation Area when the accumulated oil production from that Exploitation Area exceeds five MMbbl. Discussions with the ANH have not resolved this issue and we have initiated the dispute resolution process under the Chaza Contract by filing on January 14, 2013, an arbitration claim before the Center for Arbitration and Conciliation of the Chamber of Commerce of Bogotá, Colombia, seeking a decision that the HPR royalty is not payable until production from the Moqueta Exploitation Area exceeds five MMbbl. We supplemented our claim on May 30, 2013. The ANH has filed a response to the claim seeking a declaration that its interpretation is correct and a counterclaim seeking, amongst other remedies, declarations that we breached the Chaza Contract by not paying the disputed HPR royalty, that the amount of the alleged HPR royalty that is payable, and that the Chaza Contract be terminated. We filed a response to the ANH's counterclaim and filed our comments on the ANH defense to our claim. The ANH filed an amended counterclaim and we filed a response to the ANH's amended counterclaim. ~~As at December 31, 2014,~~In April 2015, total cumulative production from the Moqueta Exploitation Area ~~was 4.2 MMbbl.~~exceeded 5.0 MMbbl and we commenced paying the HPR royalty. The estimated compensation which would be payable on cumulative production prior to that date if the ANH is successful in the arbitration is ~~$64.1~~$66.3 million plus related interest of $26.5 million. We also disagree with the interest rate that the ANH has used in calculating the interest cost. We assert that since the HPR royalty is denominated in the U.S. dollar, the contract requires the interest rate to be three-month LIBOR plus 4%, whereas the ANH has applied the highest legally authorized interest rate on Colombian peso liabilities, which during the period of production to date has averaged approximately 29% per annum. At December 31, 2015, based on an interest rate of three-month LIBOR plus 4% related interest would be $6.4 million. At this time no amount has been accrued in the financial statements nor deducted from our reserves for the disputed HPR royalty as we do not consider it probable that a loss will be incurred.

Additionally, the ANH and Gran Tierra are engaged in discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Discussions with the ANH are ongoing. Based on our understanding of the ANH's position, the estimated compensation which would be payable if the ANH’s interpretation is correct could be up to ~~$40.6~~$44.8 million as at December 31, ~~2014.~~2015. At this time no amount has been accrued in the financial statements as we do not consider it probable that a loss will be incurred.

~~Our Business May Suffer if We do Not Attract and Retain Talented Personnel.~~

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our executive team and other personnel in conducting our business. The loss of any of these individuals or our inability to attract suitably qualified individuals to replace any of them could materially adversely impact our business. We have experienced difficulties in finding and retaining suitably qualified staff in certain jurisdictions, particularly in Brazil and Peru, where experienced personnel in our industry are in high demand and competition for their talents is intense.

Our success depends on the ability of our management and employees to interpret market and geological data successfully and to interpret and respond to economic, market and other business conditions to locate and adopt appropriate investment opportunities, monitor such investments and ultimately, if required, successfully divest such investments. Further, our key personnel may not continue their association or employment with us and we may not be able to find replacement personnel with comparable skills. If we are unable to attract and retain key personnel, our business may be adversely affected.

Maintaining Good Community Relationships and Being a Good Corporate Citizen May Be Costly and Difficult to Manage.

Our operations have a significant effect on the areas in which we operate. Maintaining good community relationships is an essential aspect of operating in the oil and gas industry. Communities have demonstrated an ability and willingness to halt operations or delay approvals.

To enjoy the ~~confidence~~support and trust of local populations and ~~the local~~ governments, we must ~~invest in~~demonstrate a commitment to: providing local employment, training and business opportunities; a high level of environmental performance; open and transparent communication; a willingness to discuss and address community issues including community development investments that are carefully selected, not unduly costly and bring lasting social and economic benefits to the ~~communities where were operate. In many cases, these communities are impoverished~~community and ~~lack many resources taken for granted in North America. The opportunities for investment are large, many and varied; however, we must invest carefully in projects that will truly benefit these areas.~~the area. Improper

management of these ~~investments and~~ relationships could lead to a delay in operations, loss of license or major impact to our reputation in these communities, which could adversely affect our business.

Competition in Obtaining Rights to Explore and Develop Oil and Gas Reserves and to Market Our Production May Impair Our Business.

The oil and gas industry is highly competitive. Other oil and gas companies will compete with us by bidding for exploration and production licenses and other properties and services we will need to operate our business in the countries in which we expect to operate. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies, which, in particular, may have access to greater resources than us, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. In the event that we do not succeed in negotiating additional property acquisitions, our future prospects will likely be substantially limited, and our financial condition and results of operations may deteriorate.

Our Business May Suffer if We do Not Attract and Retain Talented Personnel.

The Acquisitions of Petroamerica and PGC May Not Generate the Results Expected and Could be Difficult to Integrate.

In January 2016, we acquired all of the issued and outstanding shares of Petroamerica and PGC. There can be no assurance that these acquisitions will generate the expected returns and other projected results we anticipate. For example, we may not be able to achieve the anticipated synergies of the acquisitions, including expected increases in revenue and cost savings. If we fail to effectively integrate Petroamerica and PGC, our business and financial results may be adversely affected.

Foreign Currency Exchange Rate ~~Fluctuations~~Volatility May Affect Our Financial Results.

We expect to sell our oil and natural gas production under agreements that will be denominated in U.S. dollars. Many of the operational and other expenses we incur will be paid in the local currency of the country where we perform our operations. Our income taxes in Colombia are paid in Colombian pesos. As a result, we are exposed to translation risk when local currency financial statements are translated to U.S. dollars, our functional currency. We are also exposed to transaction risk on settlement of payables and receivables denominated in foreign currency. ~~We have purchased non-deliverable foreign exchange contracts to hedge some of the transaction risk related to our Colombian income tax payable. Since September~~Between January 1, ~~2005,~~2014 and February 23, 2016, exchange rates between the Colombian peso and U.S. dollar have varied between ~~1,648~~1,844 pesos to one U.S. dollar to ~~2,632~~3,440 pesos to one U.S. dollar, a fluctuation of approximately ~~60%~~87%. Production in Brazil is invoiced and paid in Brazilian Reals. Between ~~September~~January 1, ~~2005~~2014 and February ~~24, 2015,~~23, 2016, the exchange rate of the Brazilian Real has varied between ~~1.56~~2.19 Reals to one U.S. dollar to ~~2.83~~4.18 Reals to the U.S. dollar, a variance of ~~76%~~91%. Current and deferred tax liabilities in Colombia are denominated in Colombian pesos and the Colombian peso weakened by ~~24%~~32% against the U.S. dollar in the year ended December 31, ~~2014,~~2015, resulting in a foreign exchange gain.

Our Operations Involve Substantial Costs and Are Subject to Certain Risks Because the Oil and Gas Industries in the Countries in Which We Operate Are Less Developed.

The oil and gas industry in South America is not as efficient or developed as the oil and gas industry in North America. As a result, our exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. We expect that such factors will subject our international operations to economic and operating risks that may not be experienced in North American operations.

Further, we operate in remote areas and may rely on helicopter, boats or other transportation methods. Some of these transport methods may result in increased levels of risk and could lead to operational delays which could effect our ability to add to our reserve base and/or produce oil, serious injury or loss of life and could have a significant impact on our reputation or cash flow. Additionally, some of this equipment is specialized and may be difficult to obtain in our areas of operations, which could hamper or delay operations, and could increase the cost of those operations.

Exchange Controls and New Taxes Could Materially Affect Our Ability to Fund Our Operations and Realize Profits from Our Foreign Operations.

Foreign operations may require funding if their cash requirements exceed operating cash flow. To the extent that funding is required, there may be exchange controls limiting such funding or adverse tax consequences associated with such funding. In addition, taxes and exchange controls may affect the dividends that we receive from foreign subsidiaries.

The government in Brazil requires us to register funds that enter and exit the country with the central bank. In Brazil and Colombia, all transactions must be carried out in the local currency of the country. Exchange controls may prevent us from transferring funds abroad.

In Colombia, we participate in a special exchange regime, which allows us to receive revenue in U. S. dollars offshore. This regime gives us flexibility to determine the currency in which we receive our revenues, rather than to be restricted to Colombian pesos if received in Colombia, but also limits the ways in which we are able to fund our operations in Colombia. As such, this could cause us to employ funding strategies for our Colombian operations that are not as tax efficient as might otherwise be possible if we did not participate in the special exchange regime.

Tax law changes can impact the after tax profits available for expatriation. For example, in the fourth quarter of 2014 the Colombian government approved tax legislation increasing the rate of tax applicable to ordinary income from 34% in 2014 to 39% for 2015, 40% for 2016, 42% for 2017 and 43% for 2018. In the same legislation, the Colombian government also instituted a new “wealth tax” payable on the net equity of our Colombia business units at a rate of 1.15% for 2015, 1% for 2016 and 0.4% for 2017.

~~We May Be Unable to Obtain Additional Capital That We Will Require to Implement Our Business Plan, Which Could Restrict Our Ability to Grow.~~

We expect that our cash flow from existing operations and cash on hand will be sufficient to fund our currently planned activities. We may require additional capital to expand our exploration and development programs to additional properties. We may be unable to obtain additional capital required.

When we require additional capital, we plan to pursue sources of capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in locating suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do succeed in raising additional capital, future financings may be dilutive to our shareholders, as we could issue additional shares of Common Stock or other equity to investors. In addition, debt and other mezzanine financing may involve a pledge of assets and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertibles and warrants, which will adversely impact our financial results.

Our ability to obtain needed financing may be impaired by factors such as the capital markets (both generally and for the oil and gas industry in particular), the location of our oil and natural gas properties in South America, prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us), and the loss of key management. Further, if oil and/or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. The price of oil and natural gas also effects the value of our oil and natural gas reserves, which dictates our capacity to borrow using those reserves as collateral. Some of the contractual arrangements governing our exploration activity may require us to commit to certain capital expenditures, and we may lose our contract rights if we do not have the required capital to fulfill these commitments. If the amount of capital we are able to raise from financing activities, together with our cash flow from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our activities), we may be required to curtail our operations.

~~Negative Political Developments in Colombia May Negatively Affect Our Proposed Operations.~~

Adverse political incidents may generate social unrest which could impact our operations and oil deliveries in Colombia. Peace process negotiations between the government and FARC may not generate the intended outcome for both parties. With the use of arms, and other methods of influence, the FARC may place pressure on organizations and communities that are in areas of operations of the company. These communities, and affiliated organizations, can generate protests to attract the attention of government. These communities may make further use of the Local Court by filing a tutela, or writ of protection, to stop operations in Colombia until such time as these new ethnic communities obtain further consultations and benefits from companies operating in Colombia. Protests or other demonstrations may establish blockades, or the issuance of a tutela by a Local Court, could cause interruptions of operations, deliveries, and other disruptions to our work programs in the affected area.

Negative Political Developments in Peru May Negatively Affect our Proposed Operations.

Peru held a national election in June 2011 after which a new political regime was elected on a left-populist platform. The government has said that the past decade prioritized the strengthening of democracy with economic growth, while the current government will enhance social inclusion to benefit the neediest. This political regime may adopt new policies, laws and regulations that are more hostile toward foreign investment which may result in the imposition of additional taxes, the adoption of regulations that limit price increases, termination of contract rights, or the expropriation of foreign-owned assets. Such actions by the elected political regime could limit the amount of our future revenue in that country and affect our results of operations. The next general elections in Peru will be held on April 10, 2016 and the current incumbent President, Ollanta Humala, will not seek to run again for presidency in this election.

Guerrilla Activity in Peru Could Disrupt or Delay Our Operations and We Are Concerned About Safeguarding Our Operations and Personnel in Peru.

The Shining Path Guerilla group has been active in Peru since the early 1980’s and, at one point, was active throughout the country. Recently, the group’s activity has been confined to small areas of Peru and operations have been hampered by the capture of many high profile leaders and membership has fallen dramatically. During April 2012, 30 people working on the Camisea natural gas project in central Peru were kidnapped. Most of the workers were released after a short period of time, and the remainder were freed within a few days. The kidnapping was attributed to the Shining Path Guerilla group. Camisea is a very large, high profile project in an area where the group continues to be active. Our operations in Peru are in a different region, with no known activity by the group. Other groups may be active in other areas of the country and possibly our operational areas. Recently there have been security incidents and incidents of social unrest in and around our operating areas, ~~particularly~~including Block ~~107. We~~107, and activities in the areas surrounding the block are ~~monitoring~~to be considered with caution due to the ~~situation and increasing security measures as required. Nevertheless, we are concerned about~~eradication of illegal farms by the ~~security of our operations in Peru and mitigate our risks through good relationships with local communities and stakeholders as well as strong security procedures.~~government.

We May Not Be Able to Effectively Manage Our Growth, Which May Harm Our Profitability.

Our strategy envisions continually expanding our business, both organically and through acquisition of other properties and companies. If we fail to effectively manage our growth or integrate successfully our acquisitions, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. Integration efforts place a significant

burden on our management and internal resources. The diversion of management attention and any difficulties encountered in the integration process could harm our business, financial condition and results of operations. In addition, we must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new or acquired employees. We may not be able to:

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.

If we are unable to manage our growth and our operations our financial results could be adversely affected by inefficiencies, which could diminish our profitability.

The United States Government May Impose Economic or Trade Sanctions on Colombia That Could Result In a Significant Loss to Us.

Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States. Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future. A finding by the President that Colombia has failed demonstrably to meet its obligations under international counternarcotics agreements may result in any of the following:

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.

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with ANH and Ecopetrol and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets.

Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of shares of our Common Stock. The United States may impose sanctions on Colombia in the future, and we cannot predict the effect in Colombia that these sanctions might cause.

We Are Subject to the U.S. Foreign Corrupt Practices Act, a Violation of Which Could Adversely Affect Our Business.

The U.S. Foreign Corrupt Practices Act ("FCPA") and similar anti-bribery laws in other jurisdictions prohibit corporations and individuals, including us, our subsidiaries and affiliates, partners, and our employees, contractors, and agents working on behalf, from making improper payments to ~~non-U.S.~~government officials and certain other individuals and organizations for the purpose of obtaining or retaining business or engaging in certain accounting practices. We do business and may do future business in countries in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, international organizations, or private entities. As a result, we face the risk of unauthorized payments or offers of payments by employees, contractors agents, and ~~agents~~partners of ours or our subsidiaries or affiliates, even though these parties are not always subject to our control or direction. It is our policy to implement compliance procedures to prohibit these practices. However, our existing safeguards and any future improvements may prove to be less than effective or may not be followed, and our employees, contractors, agents, and partners may engage in illegal conduct for which we might be held responsible. Also, the FCPA contains certain accounting standards which obligate us to maintain accurate and complete books and records and a system of effective internal controls. These accounting provisions are very broad and a violation can occur even if there is no

evidence of a ~~bribe.~~bribe or unauthorized payment. The U.S. government is actively investigating and enforcing the FCPA and similar laws against companies and individuals. A violation of any of these laws, even if prohibited by our policies, may result in criminal or civil sanctions or other penalties (including profit disgorgement), could disrupt our business and could have a material adverse effect on our business. Actual or alleged violations could damage our reputation, be expensive to investigate and defend, and impair our ability to do business. A number of countries, including Canada and Brazil, have strengthened their anti-corruption ~~legislation.~~legislation and enforcement. These laws prohibit both domestic and international bribery. There is a risk that an act of corruption can result in a violation of not only the FCPA, but also the laws of several other ~~countries.~~countries, and expose us to investigation and enforcement outside of the U.S.

Our Business Could Be Negatively Impacted by Security Threats, Including Cybersecurity Threats as Well as Other Disasters, and Related Disruptions.

Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs. It is critical to our business that our facilities and infrastructure remain secure. ~~Although we employ data encryption processes, an intrusion detection system, and other internal control procedures to assure the security of our data, we~~We cannot guarantee that ~~these~~ measures taken to defend against cybersecurity threats will be sufficient for this purpose. The ability of the information technology function to support our business in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected interruptions cannot be fully tested and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of the breach or disaster. In that event, key information and systems may be unavailable for a number of days or weeks, leading to our inability to conduct business or perform some business processes in a timely manner. We have implemented strategies to mitigate impacts from these types of events.

We have expended significant time and money on the security of our facilities and on our information technology infrastructure including testing of our security at our facilities and infrastructure. If our security measures are breached as a result of third-party action, employee error or otherwise, and as a result our data becomes available to unauthorized parties, we may lose our competitive edge in certain of our business activities and our reputation may be damaged. If we experience any breaches of our network security or sabotage, we might be required to expend significant capital and other resources to remedy, protect against or alleviate these and related problems, and we may not be able to remedy these problems in a timely manner, or at all. Because techniques used by outsiders to obtain unauthorized network access or to sabotage systems change frequently and generally are

~~not recognized until launched against a target, we may be unable to anticipate these techniques or implement adequate preventative measures.~~

We have had past security breaches to our infrastructure, and, although they did not have a material adverse effect on our operations or our operating results, there can be no assurance of a similar result in the future. Our employees have been and will continue to be targeted by parties using fraudulent “spoof” and “phishing” emails to misappropriate information or to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails sent by us but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. Despite our efforts to mitigate “spoof” and “phishing” emails through education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure.

Risks Related to Our Industry

Unless We Are Able to Replace Our Reserves, and Develop and Manage Oil and Gas Reserves and Production on an Economically Viable Basis, Our Reserves, Production and Cash Flows May Decline as a Result.

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, our reserves and production will decline. We may not be able to find, develop or acquire additional reserves at acceptable costs.

To the extent that we succeed in discovering oil and/or natural gas, reserves may not be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and gas reserves. Without the addition of reserves through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets. Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.

Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and technical conditions. While we will endeavor to effectively manage these conditions, we may not be able to do so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

Estimates of probable and possible reserves are inherently imprecise. When producing an estimate of the amount of oil that is recoverable from a particular reservoir, 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. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of probable and possible reserves are by their nature much more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

In addition, the quantity and value of our reserves directly effects our ability to access certain kinds of external financing that uses our reserves as collateral. Low oil prices diminish the value of our oil reserves, thus diminishing not only current cash flow, but debt capacity and access to other forms of capital as well. This could impair our ability to carry out the exploration and development activity required to replace our reserves.

Prices and Markets for Oil and Natural Gas Are Unpredictable and Tend to Fluctuate Significantly, Which Could Reduce Our Profitability, Growth and Value.

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years. ~~The average price~~Spot prices for West Texas Intermediate ("WTI") declined from approximately $106 per bbl ~~has varied from $66~~ in ~~2006~~June 2014 to ~~$98~~less than $30 per bbl in ~~2013, and $93 in the year ended December 31,~~

~~2014, demonstrating the inherent volatility in the market.~~January 2016. The ~~average~~spot price for Brent oil ~~price~~declined from approximately $115 per bbl ~~was $111~~ in ~~2011, $112 in 2012, $109 in 2013 and $99.02 in the year ended December 31, 2014. At the end of~~June 2014 ~~oil prices declined sharply, and the effect of that decline is not apparent from the average price for the year. On December 31, 2014, the price of WTI was $53.27~~to less than $30 per bbl ~~and the price of Brent oil was $55.27 per bbl.~~ in January 2016.

Given the current economic environment and unstable conditions in the Middle East, North Africa, China, and Eastern Europe and the current supply of oil in world markets, the oil price environment is unpredictable and unstable. We expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our oil and gas reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contract with purchasers with prescribed deductions for transportation and quality differentials. These differentials can change over time and have a detrimental impact on realized prices. Future decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations, financing available to us, and quantities of reserves recoverable on an economic basis.

Oil prices in Colombia are related to international market prices, but adjustments that are defined by contracts with offtakers may cause realized prices to be lower or higher than those received in North America. Oil prices in Brazil are defined by contract with the refinery and may be lower or higher than those received in North America.

Our Exploration for Oil and Natural Gas Is Risky and May Not Be Commercially Successful, Impairing Our Ability to Generate Revenues from Our Operations.

Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our exploration expenditures may not result in new discoveries of oil or natural gas in commercially viable quantities or at a commercially viable cost. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. For example, in January 2014, the Corunta-1 exploration well on the west flank of the Moqueta field encountered drilling problems prior to reaching the reservoir target on this long-reach deviated well, and the decision was made to abandon the well. The target location may be drilled again in the future with a revised drilling plan. If exploration costs exceed our estimates, or if our exploration efforts do not produce results which meet our expectations, our exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations. In addition, changes in the price of oil can affect the commercial success of our exploration activity. If the oil price declines drastically, such as it did at the end of 2014 and beginning of 2015, some projects that were previously considered commercially successful may not be at low oil price levels and may be deferred, which means that our short to medium term production and cash flow may be lower than previously anticipated. For example, largely as a result of the current low commodity price environment, we reevaluated our business strategy with a renewed focus on balancing the return and risk of our exploration and development projects. As a result, on February 19, 2015, we made 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 high capital investment, associated debt financing and long-term payout horizon of this project does not align with our shift in strategy as announced on February 2, 2015. Considering the current low commodity price environment and the significant aspects of the Bretaña field project which were no longer in line with our strategy, our Board of Directors determined that they would not proceed with the further capital investment required to develop the Bretaña field. As a result of this decision, all probable and possible reserves associated with the field were reclassified as contingent resources in a report with an effective date of January 31, 2015. Further as a result, $265.1 million of unproved properties relating to Block 95 were impaired at December 31, 2014. We expect to continue to identify and evaluate all options for the Bretaña field.

~~Estimates of Oil and Natural Gas Reserves That We Make May Be Inaccurate and Our Actual Revenues May Be Lower and Our Operating Expenses May Be Higher Than Our Financial Projections.~~

We make estimates of oil and natural gas reserves, upon which we will base our financial projections. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Wells that are drilled may not achieve the results expected from interpretation of geological data. Economic factors beyond our control, such as world oil prices, interest rates and exchange rates, will also impact the value of our reserves. The process of estimating oil and gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those we

~~estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.~~

Exploration, development, production (including transportation and workover costs), marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and gas that we produce. These costs are subject to fluctuations and variation in different locales in which we operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

If Oil and Natural Gas Prices Decrease, or Our Operating Results are Different Than We Expect, We May Be Required to Take Write-Downs of the Carrying Value of Our Oil and Natural Gas Properties.

We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price during the 12 months period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is

then held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared with the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings. In countries where we do not have proved reserves, dry wells drilled in a period would directly result in an impairment for that period.

In 2012, we recorded a ceiling test impairment loss of $20.2 million in our Brazil cost center related to seismic and drilling costs on Block BM-CAL-10. The farm-out agreement for that block terminated during the first quarter of 2012 when we provided notice that we would not enter into the second exploration period. In 2013, we recorded a $2.0 million ceiling test impairment loss in our Brazil cost center related to lower realized prices and an increase in operating costs. In the year ended December 31, 2013, we recorded a ceiling test impairment loss of $30.8 million in our Argentina cost center as a result of deferred investment and inconclusive waterflood results. In 2014, we recorded an impairment loss of $265.1 million in our Peru cost center related to drilling costs on Block 95.

We Are Required to Obtain Licenses and Permits to Conduct Our Business and Failure to Obtain These Licenses Could Cause Significant Delays and Expenses That Could Materially Impact Our Business.

We are subject to licensing and permitting requirements relating to exploring and drilling for and development of oil and natural gas, including seismic, environmental and many other operating permits. We may not be able to obtain, sustain or renew such licenses and permits on a timely basis or at all. For example, the permitting process in Peru takes significant time, meaning that exploration and development projects have a longer cycle time to completion than they might elsewhere. In Colombia, other drilling and development projects are being delayed, most significantly our Moqueta field development, because of delays at the Ministry of the Environment and other government departments. During the third quarter 2014, we received the Exploitation License for the Moqueta field, however delays in receiving it contributed to operational delays and higher development costs. In addition, environmental and social evaluation demands have increased in Colombia, causing permit processing to take longer than previously experienced in the areas where we operate and, in some areas where we operate, such as the Department of Putumayo, despite the receipt of the proper permits, there are new procedures being utilized by new ethnic communities to make further economic demands on operators to continue to operate in the region, such as the use of the Local Court to obtain a tutela, or writ of protection. These delays and demands are also significantly impacting other industry participants. Regulations and policies relating to these licenses and permits may change, be implemented in a way that we do not currently anticipate or take significantly greater time to obtain. These licenses and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations. ~~For example, currently~~

Estimates of Oil and Natural Gas Reserves That We Make May Be Inaccurate and Our Actual Revenues May Be Lower and Our Operating Expenses May Be Higher Than Our Financial Projections.

We make estimates of oil and natural gas reserves, upon which we will base our financial projections. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in ~~Brazil,~~part on the ability of our management team, engineers and other advisors to make accurate assumptions. Wells that are drilled may not achieve the results expected from interpretation of geological data. Economic factors beyond our control, such as world oil prices, interest rates and exchange rates, will also impact the value of our reserves. The process of estimating oil and gas reserves is complex, and will require us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserve estimates will be inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Exploration, development, production (including transportation and workover costs), marketing (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and gas that we produce. These costs are subject to ~~restrictions on flaring natural gas,~~fluctuations and variation in different locales in which ~~have the impact of limiting our production capacity. We have examined~~

~~other alternatives for producing~~we operate, and ~~delivering the gas, however, however, to date,~~ we ~~have~~may not ~~been~~be able to ~~successfully implement any~~predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of ~~these alternatives.~~operations. In addition, we may not be able to earn net revenue at our predicted levels, which may impact our ability to satisfy our obligations.

Our Inability to Obtain Necessary Facilities and/or Equipment Could Hamper Our Operations.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities or equipment may not be proximate to our operations, which will increase our expenses. For example, our development and exploration projects in Peru are in remote areas that require barge and helicopter transportation which adds dramatically to the cost of these operations. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities or equipment may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail

unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment, transportation or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

Decommissioning Costs Are Unknown and May Be Substantial; Unplanned Costs Could Divert Resources from Other Projects.

We are responsible for costs associated with abandoning and reclaiming some of the wells, facilities and pipelines which we use for production of oil and gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have determined that we require a reserve account for these potential costs in respect of our current properties and facilities at this time, and have booked such reserve on our financial statements. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy decommissioning costs could impair our ability to focus capital investment in other areas of our business. ~~For example, our decision to not commit to further investment in the Bretaña field on Block 95 in Peru could accelerate the timing of significant decommissioning costs.~~

~~Drilling New Wells and Producing Oil and Natural Gas From Existing Facilities Could Result in New Liabilities, Which Could Endanger Our Interests in Our Properties and Assets.~~

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, craterings, sour gas releases, fires and spills. Earthquakes or weather related phenomena such as heavy rain, landslides, storms and hurricanes can also cause problems in drilling new wells. There are also risks in producing oil and natural gas from existing facilities. For example, in January 2014, the Corunta-1 exploration well on the west flank of the Moqueta field encountered drilling problems prior to reaching the reservoir target on this long-reach deviated well, and the decision was made to abandon the well. The target location may be drilled again in the future with a revised drilling plan. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. Incidents such as these can lead to serious injury, property damage and even loss of life. We generally obtain insurance with respect to these hazards, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Environmental Risks May Adversely Affect Our Business.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and federal, provincial and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances used or produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner ~~we expect may~~likely to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to foreign governments and third parties and may require us to incur costs to remedy such discharge. ~~For example, we have encountered difficulties maintaining the stability~~

of the river shoreline at our drilling and production facilities at the Bretaña field on Block 95. We will have to invest money to remediate the shoreline even though we have suspended investment in the field while we evaluate options. The application of environmental laws to our business may ~~cause~~force us to curtail our production as a result of restrictions imposed by government regulators, or increase the costs of our production, development or exploration ~~activities.~~activities because of increased compliance costs.

Penalties We May Incur Could Impair Our Business.

Our exploration, development, production and marketing operations are regulated extensively under foreign, federal, state and local laws and regulations. Under these laws and regulations, we could be held liable for personal injuries, property damage, site clean-up and restoration obligations or costs and other damages and liabilities. We may also be required to take corrective actions, such as installing additional safety or environmental equipment, which could require us to make significant capital expenditures. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages. We could be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result of these laws and regulations, our future business prospects could deteriorate and our profitability could be impaired by costs of compliance, remedy or indemnification of our employees, reducing our profitability.

Policies, Procedures and Systems to Safeguard Employee Health, Safety and Security May Not Be Adequate.

Oil and natural gas exploration and production is dangerous. Detailed and specialized policies, procedures and systems are required to safeguard employee health, safety and security. We have undertaken to implement what we believe to be best practices for employee health, safety and security; however, if these policies, procedures and systems are not adequate, or employees do not receive adequate training, the consequences can be severe including serious injury or loss of life, which could impair our operations and cause us to incur significant legal liability.

Our Insurance May Be Inadequate to Cover Liabilities We May Incur.

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blowouts, property damage, personal injury or other hazards. ~~Although we have insurance in accordance with industry standards to address such risks, such~~Our insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not

solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

Challenges to Our Properties May Impact Our Financial Condition.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interest in and to the properties to which the title defects relate.

Furthermore, applicable governments may revoke or unfavorably alter the conditions of exploration and development authorizations that we procure, or third parties may challenge any exploration and development authorizations we procure. Such rights or additional rights we apply for may not be granted or renewed on terms satisfactory to us.

If our property rights are reduced, whether by governmental action or third party challenges, our ability to conduct our exploration, development and production may be impaired. See the risk factor "Disputes or Uncertainties May Arise in Relation to Our Royalty Obligations" for a description of our dispute with the ANH regarding royalties payable on our Chaza Block and the resulting challenge to our contract for that block.

We Will Rely on Technology to Conduct Our Business and Our Technology Could Become Ineffective or Obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration and development and production activities. We will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial, and

may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

Risks Related to Our Common Stock

The Market Price of Our Common Stock May Be Highly Volatile and Subject to Wide Fluctuations.

The market price of shares of our Common Stock may be highly volatile and could be subject to wide fluctuations in response to a number of factors that are beyond our control, including but not limited to:

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.

In addition, the market price of shares of our Common Stock could be subject to wide fluctuations in response to various factors, which could include the following, among others:

quarterly variations in our revenues and operating expenses; and

additions and departures of key personnel.

updated reserve estimates by independent parties.

These and other factors are largely beyond our control, and the impact of these risks, singularly or in the aggregate, may result in material adverse changes to the market price of shares of our Common Stock and/or our results of operations and financial condition.

We do Not Expect to Pay Dividends in the Foreseeable Future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their shares of Common Stock, and shareholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in shares of our Common Stock.

Item 1B. Unresolved Staff Comments

None.

~~Item 2.~~ ~~Properties~~

We have described our properties, reserves, acreage, wells, production and drilling activity in Part I, Item 1. “Business” of this Annual Report on Form 10-K, which information and descriptions are incorporated by reference here.

~~Administrative Facilities~~

Our executive offices are located in Calgary, Canada. Our primary executive offices comprise approximately 29,000 square feet, which we lease for approximately $79,000 per month under a lease that expires on December 30, 2018. We lease administrative office space in Colombia, Peru and Brazil. We believe that our current executive and administrative offices are sufficient for our purposes or, to the extent that we need additional office space, that additional office space will be readily available to us.

Item 3. Legal Proceedings

As discussed above (see “Royalties”, above, in Item 1), Gran Tierra’s production from the Costayaco Exploitation Area is subject to the HPR royalty, which applies when cumulative gross production from an Exploitation Area is greater than five MMbbl. The HPR royalty is calculated on the difference between a trigger price defined in the Chaza Contract and the sales price. The ANH has interpreted the Chaza Contract as requiring that the HPR royalty must be paid with respect to all production from the Moqueta Exploitation Area and initiated a noncompliance procedure under the Chaza Contract, which was contested by Gran Tierra because the Moqueta Exploitation Area and the Costayaco Exploitation Area are separate Exploitation Areas. ANH did not proceed with that noncompliance procedure. Gran Tierra also believes that the evidence shows that the Costayaco and Moqueta ~~fields~~Fields are two clearly separate and independent hydrocarbon accumulations. Therefore, it is Gran Tierra’s view that, pursuant to the terms of the Chaza Contract, the HPR royalty is only to be paid with respect to production from the Moqueta Exploitation Area when the accumulated oil production from that Exploitation Area exceeds five MMbbl. Discussions with the ANH have not resolved this issue and Gran Tierra has initiated the dispute resolution process under the Chaza Contract by filing on January 14, 2013, an arbitration claim before the Center for Arbitration and Conciliation of the Chamber of Commerce of Bogotá, Colombia, seeking a decision that the HPR royalty is not payable until production from the Moqueta Exploitation Area exceeds five MMbbl. Gran Tierra supplemented its claim on May 30, 2013. The ANH has filed a response to the claim seeking a declaration that its interpretation is correct and a counterclaim seeking, amongst other remedies, declarations that Gran Tierra breached the Chaza Contract by not paying the disputed HPR royalty, that the amount of the alleged HPR royalty that is payable, and that the Chaza Contract be terminated. Gran Tierra filed a response to the ANH's counterclaim and filed its comments on the ANH defense to Gran Tierra's claim. The ANH filed an amended counterclaim and Gran Tierra filed a response to the ANH's amended counterclaim. ~~As at~~ ~~December 31, 2014~~,On April 30, 2015, total cumulative production from the Moqueta Exploitation Area ~~was~~ ~~4.2~~ ~~MMbbl.~~reached 5.0 MMbbl and Gran Tierra commenced paying the HPR royalty payable on production over that threshold. The estimated compensation which would be payable on cumulative production ~~to that date~~ if the ~~ANH is successful~~ANH's claims are accepted in the arbitration is ~~$64.1~~$66.3 million. plus related interest of $26.5 million. We also disagree with the interest rate that the ANH has used in calculating the interest cost. We assert that since the HPR royalty is denominated in the U.S. dollar, the

contract requires the interest rate to be three-month LIBOR plus 4%, whereas the ANH has applied the highest legally authorized interest rate on Colombian peso liabilities, which during the period of production to date has averaged approximately 29% per annum. At December 31, 2015, based on an interest rate of three-month LIBOR plus 4% related interest would be $6.4 million. At this time, no amount has been accrued in the financial statements nor deducted from our reserves for the disputed HPR royalty as Gran Tierra does not consider it probable that a loss will be incurred.

Additionally, the ANH and Gran Tierra are engaged in discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Discussions with the ANH are ongoing. Based on our understanding of the ANH's position, the estimated compensation which would be payable if the ANH’s interpretation is correct could be up to $~~40.6~~44.8 million as at December 31, ~~2014~~2015. At this time no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

We have several other lawsuits and claims pending. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we believe the resolution of these matters would not have a material adverse effect on our consolidated financial position, results of operations or cash flows. We record costs as they are incurred or become probable and determinable.

Item 4. Mine Safety Disclosures

Not applicable.

~~End of Item 4~~

Executive Officers of the Registrant

Set forth below is information regarding our executive officers as of February ~~24, 2015~~23, 2016.



Name	Age	Position
~~Jeffrey J. Scott~~Gary S. Guidry	5260	~~Executive Chairman of the Board; Director~~
~~Duncan Nightingale~~	56	~~Interim~~ President and Chief Executive Officer, Director
~~James Rozon~~Ryan Ellson	5140	Chief Financial Officer
Adrian Coral	42	President, Gran Tierra Energy Colombia
James Evans	50	Vice President, Corporate Services
David Hardy	6061	Vice-President, Legal, Secretary and General Counsel
~~Adrian Coral~~Alan Johnson	4144	Vice President, ~~Gran Tierra Energy Colombia~~Asset Management
~~Carlos Monges~~Lawrence West	5859	Vice President, ~~Gran Tierra Energy Peru~~Exploration

~~Jeffrey J. Scott,~~Gary Guidry, Chief Executive ~~Chairman~~Officer and President. Mr. Guidry has been Gran Tierra's Chief Executive Officer and President since May 7, 2015. Mr. Guidry was the Chief Executive Officer of ~~the Board.~~ Mr. Scott has served as Executive Chairman of our Board since February 2015, and served as Chairman of our Board of directors since January 2005. Since 2001, Mr. Scott has served as President of Postell Energy Co. Ltd., a privately held oil and gas producing company. He has extensive oil and gas management experience, beginning as a production manager of Postell Energy Co. Ltd in 1985 advancing to President in 2001. Also, since February 2012, Mr. Scott has served as Executive Chairman of Sulvaris Inc., a private fertilizer technology company. Mr. Scott is also currently a director of PetromanasOnza Energy Inc. He was previously a director of Tuscany International Drilling Inc., Essential Energy Services Trust, Suroco Energy, Inc., VGS Seismic Canada Inc., High Plains Energy Inc., Saxon Energy Services Inc., Galena Capital Corp. and Gallic Energy Ltd., all of which are publicly-traded companies.from January 2014, until May 2015. From July 2011 to July 2014, Mr. ~~Scott holds a Bachelor of Arts degree from the University of Calgary, and a Masters of Business Administration from California Coast University.~~

~~Duncan Nightingale, Interim~~Guidry served as President and Chief Executive Officer. of Caracal Energy Inc. Mr. ~~Nightingale joined Gran Tierra in September~~Guidry also served as President and CEO of Orion Oil & Gas Corp. from October 2009 to July 2011, Tanganyika Oil Corp. from May 2005 to January 2009, and Calpine Natural Gas Trust from October 2003 to February 2005. As chief executive officer of these companies, Mr. Guidry was responsible for overseeing all aspects of the respective company’s business. Mr. Guidry currently sits on the boards of Africa Oil Corp. (since April 2008) and Shamaran Petroleum Corp. (since February 2007), where he also serves as a member of each company’s Audit Committee. From September 2010 to October 2011, Mr. Guidry also served ~~in our Calgary, Canada office as our Vice President~~on the Board of Zodiac Exploration Corp., and from ~~September~~October 2009 to ~~January 2011. He~~March 2014, he served in our Bogotá, Colombia office as our Senior Manager Project Planning and Exploration from January 2011 until August 2011 and in our Calgary office as Chief Operating Officer from August 2011 to February 2, 2015. On February 2, 2015, Mr. Nightingale was promoted to Interim President and Chief Executive Officer.on the board of TransGlobe Energy Corp. Prior to ~~joining Gran Tierra,~~these positions, Mr. ~~Nightingale was~~Guidry served as Senior Vice President ~~Exploration & Production, at Artumas Group Inc., a~~and subsequently President of Alberta Energy Company International, and President and General Manager of Canadian ~~oil and gas company focusing on exploration and development of hydrocarbon reserves in Tanzania and Mozambique, where he was responsible for Artumas Group’s~~Occidental Petroleum’s Nigerian operations. Mr. Guidry has directed exploration and production operations in ~~Mozambique~~Yemen, Syria and ~~Tanzania~~Egypt and ~~management~~has worked for oil and gas companies around the world in the U.S., Colombia, Ecuador, Venezuela, Argentina and Oman. Mr. Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University.

Ryan Ellson, Chief Financial Officer. Mr. Ellson has been Gran Tierra's Chief Financial Officer since May 2015. Mr. Ellson has 15 years of ~~its gas processing plant~~experience in a broad range of international corporate finance and ~~power generation facility~~accounting roles. Mr. Ellson was CFO of Onza Energy Inc. from January 2015 to May 2015. From July 2014 until December 2014 Mr. Ellson was Head of Finance for Glencore E&P (Canada) and prior thereto Vice President, Finance at Caracal Energy, a London Stock Exchange listed company with operations in ~~Tanzania.~~Chad, Africa from August 2011 until July 2014. Prior to ~~Artumas Group,~~Caracal, Mr. ~~Nightingale~~Ellson was ~~General Manager, Exploration & Production, with Dana Gas PJSC,~~Vice President of Finance at Sea Dragon Energy from April 2010 until August 2011. In these positions, Mr. Ellson oversaw financial and accounting functions, implemented and oversaw internal financial controls, secured a ~~leading private sector natural gas company in the Middle East, where Mr. Nightingale was responsible for all of Dana Gas’s exploration and production operations~~reserve based lending facility and was ~~responsible for~~involved in multiple capital raises. Mr. Ellson has held management and executive positions with companies operating in Chad, Egypt, India and Canada. Mr. Ellson is a ~~multi-million dollar exploration~~Chartered Accountant and ~~development program~~holds a Bachelor of Commerce and a Master of Professional Accounting from the University of Saskatchewan.

Adrian Coral, President, Gran Tierra Energy Colombia. Mr. Coral joined Gran Tierra in ~~Kurdistan. Prior to Dana Gas,~~August 2006 as an operations engineer in Gran Tierra Energy Colombia, Ltd., and served in that capacity until February 2007. Mr. ~~Nightingale was with Encana Corporation’s International Division from May 2002 until March 2007. From June 2002~~Coral rejoined Gran Tierra in August 2008 as Operations Director of Gran Tierra Energy Colombia, Ltd. He served in that capacity until September ~~2003,~~2011, when he was ~~the Country~~promoted to Production Manager of Gran Tierra Energy Colombia, Ltd. Mr. Coral was promoted to Senior Operations Manager of Gran Tierra Energy Colombia, Ltd. in Qatar, responsible for managing Encana’s activities in Qatar, including the execution of exploration programs and new venture activity. From October 2003 until June 2006, he had similar responsibilities in the Sultanate of Oman, where he served as Encana’s Country Manager.April 2013. On August 1, 2014, Mr. ~~Nightingale~~Coral was promoted to President, Gran Tierra Energy Colombia. Mr. Coral has a total of 3018 years of ~~corporate head office~~experience as an engineer or manager in the oil and resident in-country international operating experience, spanning all aspects of managing exploration programs, development and production operations, new business ventures, portfolio management and strategic planning.gas industry. Mr. ~~Nightingale~~Coral graduated from the ~~University of Nottingham in the U.K.~~Universidad de América – Bogotá D.C. with a ~~Bachelor~~degree as a Petroleum Engineer and from the School of ~~Science~~Business Management – Bogotá D.C with degree ~~with honors~~ in ~~Geology.~~Project Management.

James ~~Rozon, Chief Financial Officer~~Evans, Vice President, Corporate Services. ~~. On~~Mr. Evans has been Gran Tierra's Vice President, Corporate Services, since May ~~2, 2012, James Rozon was promoted from acting Chief Financial Officer to Chief Financial Officer.~~2015. Mr. ~~Rozon had been serving as acting Chief Financial Officer since December 9, 2011. Mr. Rozon served as Gran Tierra’s Corporate Controller from October 1, 2007 to December 9, 2011. He~~Evans has ~~previous~~over 20 years of experience ~~in accounting, finance and administration~~including working the last 10 years in the ~~petroleum and technology industries in Canada. During his career, his responsibilities have included management of finance related activities of Canadian and American~~international oil and gas ~~exploration and production companies operating in Canada and~~industry. Most recently, Mr. Evans was the ~~United States and a software development company operating in Canada, the United States, China and Sweden. He was Controller~~Head of ~~Sound Energy Trust, a publicly listed Canadian oil and gas trust~~Compliance & Corporate Services for Glencore E&P (Canada) from July ~~2006~~2014 to ~~September 2007,~~December 2014, and prior thereto Vice President of Compliance & Corporate Services at ~~which time it was sold. From October 2002 to June 2006, and previously~~Caracal Energy from July 1995 to February 1998, he was the Corporate Controller of Zi Corporation, a Canadian software development company publicly listed in both Canada and the United States of America. From June 2000 to September 2002, he was the Controller for Energy Exploration Technologies, an American publicly listed oil and gas exploration company operating in Canada and the United States. From April 1998 to May 2000, he was the Manager, Financial Reporting of Summit Resources Limited, a publicly listed Canadian oil and gas exploration and development company with operations in Canada and the United States of America. From June 1990 to June 1995, Mr. Rozon worked in public practice for five years for Deloitte & Touche LLP including one year as an audit manager in the Oil and Gas group in the Calgary, Alberta

4943

~~office.~~2011 to June 2014, in each case where he oversaw the execution of corporate strategy and goals, developed and implemented a robust corporate compliance program, and managed all aspects of IT, document control, security and administration. Mr. ~~Rozon~~Evans also managed the recruitment, training and retention of staff in both Calgary and Chad. He oversaw the growth of Caracal Energy from seven employees to in excess of 400 as Caracal Energy exceeded 20,000 barrels of oil per day at the time of sale to Glencore. Prior to Caracal, Mr. Evans held senior management and executive positions at Orion Oil and Gas and Tanganyika Oil, with operating experience in Egypt, Syria and Canada. Mr. Evans is a Certified General Accountant and holds a Bachelor of Commerce degree from the University of ~~Saskatchewan and is a member of the Institute of Chartered Accountants of Alberta and the Institute of Chartered Accountants of Saskatchewan.~~Calgary.

David Hardy, Vice President, Legal, and Secretary and General Counsel. Mr. Hardy joined Gran Tierra as General Counsel, Vice President Legal and Secretary on March 1, 2010. He has more than 2025 years’ experience in the legal profession. Before joining Gran Tierra, he worked for Encana Corporation and for Encana Corporation’s predecessor, Pan Canadian, from 2000 through 2009 where he held various positions, including: Vice President Divisional Legal Services, Integrated Oil and Canadian Plains Divisions; Vice President Regulatory Services, Corporate Relations Division; and Associate General Counsel, Offshore and International Division. For four of his eight years in the Offshore and International Division of Encana, Mr. Hardy led the Legal and Commercial Negotiations Group, where he was responsible for providing strategic legal, commercial and negotiation advice and support to the offshore and international business units. This included dealing with new venture activities and operational, joint venture and host government issues relating to projects in various countries, including Australia, Brazil, Chad, Libya, Oman, Qatar and Yemen. Prior to joining Encana, Mr. Hardy spent over 10 years in private practice and was a partner in a law firm in Calgary, Alberta. He holds a Juris Doctor Degree from the University of Calgary (converted from an LL.B Degree in 2011) and is a member of the Law Society of Alberta and the Association of International Petroleum Negotiators.

~~Adrian Coral,~~Alan Johnson, Vice President, Asset Management. Mr. Johnson has been Gran ~~Tierra Energy Colombia~~.Tierra's Vice President, Asset Management, since May 2015. Mr. ~~Coral joined Gran Tierra in August 2006 as an operations~~Johnson is a professional engineer in Gran Tierra Energy Colombia, Ltd., and served in that capacity until February 2007. Mr. Coral rejoined Gran Tierra in August 2008 as Operations Director of Gran Tierra Energy Colombia, Ltd. He served in that capacity until September 2011, when he was promoted to Production Manager of Gran Tierra Energy Colombia, Ltd. Mr. Coral was promoted to Senior Operations Manager of Gran Tierra Energy Colombia, Ltd. in April 2013. On August 1, 2014, Mr. Coral was promoted to President, Gran Tierra Energy Colombia. Mr. Coral has a total of 18with more than 20 years of experience ~~as an engineer or manager~~working internationally in the oil and gas industry. His experience includes varied technical, managerial and executive roles in drilling, production, reservoir, reserves, corporate planning and asset management. Most recently Mr. ~~Coral~~Johnson was Head of Asset Management for Glencore E&P (Canada) from April 2014 to April 2015, where he was responsible for all development activities in Chad and prior thereto Director of Asset Management at Caracal Energy from August 2011 to March 2014, where he was responsible for development activities in the Doba basin in Chad, Africa. Mr. Johnson was instrumental in developing oil and gas assets in remote areas of southern Chad, achieving first production in less than 18 months. Mr. Johnson started his E&P career with Shell International in the Dutch North Sea. He then held positions of increasing responsibility with Shell Canada, APF Energy, Rockyview Energy, Delphi Energy and BG Australia. Mr. Johnson graduated ~~from the Universidad de América – Bogotá D.C.~~ with a ~~degree as~~1st Class B. Eng (Hons) from Heriot Watt University in Scotland. Mr. Johnson is a ~~Petroleum~~Chartered Engineer in the UK and ~~from the School of Business Management – Bogotá D.C with degree~~a Professional Engineer in ~~Project Management.~~Alberta.

~~Carlos Monges,~~Lawrence West. Vice President, ~~Gran Tierra Energy Peru.~~Exploration. Mr. ~~Monges~~West has ~~over 30~~been Gran Tierra's Vice President, Exploration, since May 2015. Mr. West has thirty-five years of experience as an executive, explorationist, and geologist. Most recently, Mr. West was Vice President, Exploration at Caracal Energy from July 2011 to June 2014. Mr. West built a multi-disciplinary team to assess resources and grow reserves in the ~~oil industry. He joined our company upon its acquisition of Petrolifera Petroleum Limited ("Petrolifera")~~interior rift basins within Chad and led a successful exploration program. During his tenure he successfully executed two large 2D/3D seismic shoots in ~~March 2011. He~~remote frontier basins, on time and on budget. Prior to Caracal he has been involved in starting and growing several public and private companies, including Reserve Royalty Corp., Chariot Energy, Auriga Energy and Orion Oil and Gas. Lawrence worked at Alberta Energy Company (AEC), where he was ~~Petrolifera’s country manager in Peru since 2005, with responsibility for management and exploratory operations in three onshore blocks. He was the senior geologist~~ on the team that ~~performed for PeruPetro S.A. ("PeruPetro") a geological~~merged with Conwest. He built and ~~geophysical assessment of Peru’s hydrocarbon basins which was sponsored by~~led the ~~Canadian~~AEC East team to the Rocky Mountain USA basins. His career began with Imperial Oil working on prospect and ~~Peruvian governments. Prior to that, Mr. Monges was the Operations Manager for Energy Development, Anadarko Petroleum~~reservoir characterization, in multi-disciplinary teams, and ~~then BPZ Energy with respect to various offshore and onshore blocks in Peru. He began his career in the industry working~~ as a field development geologist and a well-site and production geologist in Talara Basin for Petróleos del Perú S.A. and Occidental Petroleum and also worked as a mud engineer in drilling operations in Venezuela and Argentina. Mr. Monges received histechnical mentor to exploration teams. Lawrence has an Honours Bachelor of Science ~~Degree~~ in ~~Geological Engineering~~Geology from ~~Universidad Nacional Mayor de San Marcos, Lima~~McMaster University and an MBA, specializing in ~~1978, performed studies on exploration techniques at Robertson Research Center in United Kingdom in 1990, and completed certificate studies on oil industry management at~~economics, from the ~~IHRDC program in Boston, USA in 1997. He is a current member and past director~~University of ~~the Peruvian Geological Society.~~Calgary.

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Shares of our Common Stock trade on the NYSE MKT and on the Toronto Stock Exchange ("TSX") under the symbol “GTE”. In addition, the exchangeable shares in one of our subsidiaries, Gran Tierra Exchangeco, are listed on the TSX and are trading under the symbol “GTX”.

As of February ~~24, 2015~~,23, 2016, there were approximately: 35 holders of record of shares of our Common Stock and ~~276,108,951~~287,129,518 shares outstanding with $0.001 par value; and one share of Special A Voting Stock, $0.001 par value representing approximately ~~six~~four holders of record of ~~4,524,627~~3,638,889 exchangeable shares which may be exchanged on a 1-for-1 basis into shares of our Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing ~~nineteen~~sixteen holders of record of ~~5,558,518~~4,903,177 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into shares of our Common Stock.

For the quarters indicated from January 1, ~~2013~~2014, through the end of the fourth quarter of ~~2014~~2015, the following table shows the high and low closing sale prices per share of our Common Stock as reported on the NYSE MKT.


	High		Low		High		Low
Fourth Quarter 2015					$	2.91	$	2.01
Third Quarter 2015					$	2.92	$	1.91
Second Quarter 2015					$	3.87	$	2.72
First Quarter 2015					$	3.93	$	2.10
Fourth Quarter 2014	$	5.43	$	3.11	$	5.43	$	3.11
Third Quarter 2014	$	8.04	$	5.54	$	8.04	$	5.54
Second Quarter 2014	$	8.12	$	6.97	$	8.12	$	6.97
First Quarter 2014	$	7.74	$	6.82	$	7.74	$	6.82
Fourth Quarter 2013	$	7.92	$	6.86
Third Quarter 2013	$	7.36	$	6.01
Second Quarter 2013	$	6.53	$	5.21
First Quarter 2013	$	6.12	$	5.00

We purchase Colombian peso non-deliverable forward contracts for purposes of fixing the exchange rate at which we will purchase or sell Colombian pesos to settle our income tax installments and payments. Under the terms of our foreign exchange forward contracts, we will receive Colombian pesos and pay U.S. dollars or pay Colombian pesos and receive U.S. dollars based on a total notional amount.

The fair value of foreign currency derivatives is based on the maturity value of the foreign exchange non-deliverable forward contracts, using applicable forward exchange rates. The most significant variable to the cash flow calculations is the estimation of forward foreign exchange rates. The resulting net future cash inflows or outflows at maturity of the contracts are the net value of the contract.

Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations because we utilize a group of investment-grade rated counterparties, primarily financial institutions, for our derivative transactions. Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.

Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true.

New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers". The ASU creates a single source of revenue guidance for all companies in all industries and requires revenue recognition to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 sets forth a new revenue recognition model that requires identifying the contract, identifying the performance obligations, determining the transaction price, allocating the transaction price to performance obligations and recognizing the revenue upon satisfaction of performance obligations. The amendments in the ASU can be applied either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the update recognized at the date of the initial application along with additional disclosures. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date". The ASU defers the effective date of the new revenue recognition model by one year. As a result, the guidance will be effective for fiscal years, and interim periods within those years, beginning after December 15, ~~2016.~~2017. We are currently assessing the impact the new standard will have on its consolidated financial position, results of operations, cash flows and disclosure.

In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory". The ASU provides guidance for the subsequent measurement of inventory and requires that inventory that is measured using average cost be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The implementation of this update is not expected to materially impact our consolidated financial position, results of operations or cash flows or disclosure.

In September 2015, the FASB issued ASU 2015-16, "Simplifying the Accounting for Measurement-Period Adjustments". ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years and interim reporting periods within those fiscal years, beginning after December 15, 2015. Prospective adoption is required. This ASU is not expected to have a material impact on our consolidated financial position, results of operations or cash flows or disclosure.

84In November 2015, the FASB issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes". ASU 2015-17 requires that deferred tax liabilities and assets be classified as long-term in a classified balance sheet. ASU 2015-17 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2016. Early application is permitted. The amendments in this ASU may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We implemented this update retrospectively in our consolidated financial statements for the year ended December 31, 2015, so that the balance sheet is presented on a comparable basis. Deferred tax liabilities and assets of $1.0 million and $1.6 million, respectively, have been reclassified from current to long-term in our December 31, 2014 balance sheet. The implementation of this update did not impact our consolidated results of operations or cash flows.

In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities". ASU 2016-01 addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. ASU 2016-01 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. This ASU is not expected to have a material impact our consolidated financial position, results of operations or cash flows or disclosure.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Oil prices started falling in ~~September~~July 2014 and ~~have fallen~~fell dramatically induring the period December 2014 to March 2015. Prices have remained low and ~~January 2015.~~volatile. Most of our revenues are from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to West Texas Intermediate ("WTI") or Brent and adjusted for quality each month.

Foreign currency risk

Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. We have engaged in non-deliverable foreign exchange contracts to buy or sell Colombian pesos in order to fix the exchange rate of our income tax installments and payments in Colombia. At December 31, 2014, we held Colombia peso non-deliverable forward contracts totaling 61.9 billion Colombian pesos.

Our reporting currency is U.S. dollars and essentially 100% of our revenues are related to the U.S. dollar price of WTI or Brent oil.

In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Brazil, prices for oil are in U.S.

dollars, but revenues are received in local currency translated according to current exchange rates. The majority of our capital expenditures within Brazil are based on U.S. dollar prices, but are paid in local currency translated according to current exchange rates. In Peru, capital expenditures are based on U.S. dollar prices and may be paid in local currency or U.S. dollars. The majority of income and value added taxes and G&A expenses in all locations are in local currency. While we operate in South America exclusively, the majority of our acquisition expenditures have been valued and paid in U.S. dollars.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our current and deferred tax liabilities, which are monetary liabilities, denominated in the local currency of the Colombian foreign operations. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. A strengthening in the Colombian peso against the U.S. dollar results in foreign exchange losses, estimated at ~~$60,000~~$10,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

We have engaged, from time to time, in non-deliverable foreign exchange contracts to buy or sell Colombian pesos in order to fix the exchange rate of our income tax installments and payments in Colombia. At December 31, 2015, we did not have any open foreign currency derivative positions.

The table below provides information about our foreign currency forward exchange agreements at December 31, 2014, including the notional amounts and weighted average exchange rates by expected (contractual) maturity dates. ~~We did not hold any foreign currency forward exchange agreements at December 31, 2013.~~ Expected cash flows from the forward contract ~~equal~~equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. The increase or decrease in the value of the forward contract is offset by the increase or decrease to the U.S. dollar equivalent of the Colombian peso current tax liabilities. We do not hold any of these investments for trading purposes.



As at December 31, 2014
Currency	Contract Type	Notional (Millions of Colombian pesos)	Weighted Average Fixed Rate Received (Colombian pesos - U.S. Dollars)	Fair Value of the Forward Contracts (thousands of U.S. Dollars)		Expiration
Colombian pesos	Buy	51,597.5	2,006	(4,175	)	February and April 2015
Colombian pesos	Sell	10,275.3	1,895	1,118		February 2015

Interest Rate Risk

We consider our exposure to interest rate risk to be immaterial. Our interest rate exposures primarily relate to our investment portfolio. Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes. We have no debt.

Equity Investment in Madalena Energy Inc.

We hold an equity investment in Madalena, ~~Energy Inc. ("Madalena"),~~ received as consideration in the sale of our Argentina business unit, which closed June 25, 2014. We hold 29,831,537 shares of Madalena which had a value of ~~$13.9~~$6.3 million ~~on June 25, 2014,~~ and $7.6 million at December 31, 2015 and 2014, respectively, and represented approximately ~~5.7%~~5.5% of Madalena's outstanding shares at December 31, 2015 and 2014. These shares trade on the TSX Venture Exchange and as such are subject to changes in value that are outside of our control. ~~Pursuant to Canadian securities regulation, we were unable to trade these shares before October 26, 2014. In addition, we~~We may face other market related obstacles such as trading volume and value in divesting these shares.

8674

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Gran Tierra Energy Inc.

We have audited the accompanying consolidated ~~financial statements~~balance sheets of Gran Tierra Energy Inc. and subsidiaries (the "Company")~~, which comprise the consolidated balance sheets~~ as at of December 31, ~~2014~~2015 and ~~December 31, 2013,~~2014, and the related consolidated statements of operations and retained earnings, ~~consolidated statements of~~cash flows and shareholders' equity ~~and consolidated statements of cash flows~~ for each of the years in the three-year period ended December 31, ~~2014, and a summary of significant accounting policies and other explanatory information.~~

~~Management's Responsibility for the Consolidated Financial Statements~~

~~Management is responsible for the preparation and fair presentation of these~~2015. These consolidated financial statements ~~in accordance with accounting principles generally accepted in~~are the ~~United States~~responsibility of ~~America, and for such internal control as management determines is necessary to enable~~ the ~~preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.~~

~~Auditor's Responsibility~~

Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with ~~Canadian generally accepted auditing standards and~~ the standards of the Public Company Accounting Oversight Board (United States). and Canadian generally accepted auditing standards. Those standards require that we ~~comply with ethical requirements and~~ plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free ~~from~~of material misstatement.

An audit ~~involves performing procedures to obtain audit~~includes examining, on a test basis, evidence ~~about~~supporting the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes ~~evaluating~~assessing the ~~appropriateness of~~ accounting ~~policies~~principles used and ~~the reasonableness of accounting~~significant estimates made by management, as well as evaluating the overall ~~presentation of the consolidated~~ financial ~~statements.~~

statement presentation. We believe that ~~the audit evidence we have obtained in~~ our audits ~~is sufficient and appropriate to~~ provide a reasonable basis for our ~~audit~~ opinion.

~~Opinion~~

In our opinion, ~~the~~such consolidated financial statements present fairly, in all material respects, the financial position of Gran Tierra Energy Inc. and subsidiaries as at of December 31, ~~2014~~2015 and ~~December 31,~~ ~~2013~~,2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, ~~2014~~2015 in ~~accordance~~conformity with ~~the~~ accounting principles generally accepted in the United States of America.

~~Other Matter~~

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),

the Company's internal control over financial reporting as of December 31, ~~2014~~,2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February ~~27, 2015~~26, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte LLP

Chartered Professional Accountants, Chartered Accountants

February ~~27, 2015~~26, 2016

Calgary, Canada

8775

Gran Tierra Energy Inc.

Consolidated Statements of Operations and Retained Earnings

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

Year Ended December 31,
2014 2013 2012
REVENUE AND OTHER INCOME
Oil and natural gas sales $ 559,398
$ 646,955
$ 503,467
Interest income 2,856
2,174

1,709
562,254
649,129
505,176
EXPENSES
Operating 113,949
110,172
92,207
Depletion, depreciation, accretion and impairment 451,003
202,851
150,570
General and administrative 51,249
41,115
46,659
Financial instruments loss (Note 13) 4,722
—
—
Other loss (Note 12) —
4,400
—
Other gain (Notes 10 and 12) (2,000 ) —
(9,336 )
Foreign exchange (gain) loss (39,535 ) (18,693 ) 28,727
579,388
339,845
308,827

(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (17,134 ) 309,284
196,349
Income tax expense (Note 10) (127,215 ) (128,261 ) (96,267 )
(LOSS) INCOME FROM CONTINUING OPERATIONS (144,349 ) 181,023
100,082
  Loss from discontinued operations, net of income taxes (Note 3) (26,990 ) (54,735 ) (423 )
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (171,339 ) 126,288
99,659
RETAINED EARNINGS, BEGINNING OF YEAR 410,961
284,673
185,014
RETAINED EARNINGS, END OF YEAR $ 239,622
$ 410,961
$ 284,673

INCOME (LOSS) PER SHARE
BASIC
  INCOME (LOSS) FROM CONTINUING OPERATIONS $ (0.51 ) $ 0.64
$ 0.35
  LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES (0.09 ) (0.19 ) 0.00
  NET INCOME (LOSS)
$ (0.60 )
$ 0.45
$ 0.35
DILUTED
  INCOME (LOSS) FROM CONTINUING OPERATIONS $ (0.51 ) $ 0.63
$ 0.35
  LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES (0.09 ) (0.19 ) 0.00
  NET INCOME (LOSS)
$ (0.60 )
$ 0.44
$ 0.35
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 8) 284,715,785
282,808,497
280,741,255
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 8) 284,715,785
286,127,897
284,172,254



	Year Ended December 31,
	2015			2014			2013
OIL AND NATURAL GAS SALES	$	276,011		$	559,398		$	646,955

EXPENSES
Operating	75,565			89,753			91,223
Transportation	40,204			24,196			18,949
Depletion, depreciation and accretion	176,386			185,877			200,851
Asset impairment (Note 6)	323,918			265,126			2,000
General and administrative	32,353			51,249			41,115
Severance expenses (Note 13)	8,990			—			—
Equity tax (Note 9)	3,769			—			—
Foreign exchange gain	(17,242		)	(39,535		)	(18,693		)
Financial instruments loss (Note 12)	2,027			4,722			—
Other loss (Note 11)	—			—			4,400
Other gain (Note 11)	(502		)	(2,000		)	—
	645,468			579,388			339,845

INTEREST INCOME	1,369			2,856			2,174

(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(368,088		)	(17,134		)	309,284
INCOME TAX (EXPENSE) RECOVERY
Current (Note 9)	(15,383		)	(92,865		)	(157,126		)
Deferred (Note 9)	115,442			(34,350		)	28,865
	100,059			(127,215		)	(128,261		)
(LOSS) INCOME FROM CONTINUING OPERATIONS	(268,029		)	(144,349		)	181,023
Loss from discontinued operations, net of income taxes (Note 3)	—			(26,990		)	(54,735		)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	(268,029		)	(171,339		)	126,288

INCOME (LOSS) PER SHARE
BASIC
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.94	)	$	(0.51	)	$	0.64
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			(0.09		)	(0.19		)
NET INCOME (LOSS)	$	(0.94	)	$	(0.60	)	$	0.45
DILUTED
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.94	)	$	(0.51	)	$	0.63
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	—			(0.09		)	(0.19		)
NET INCOME (LOSS)	$	(0.94	)	$	(0.60	)	$	0.44
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 7)	285,333,869			284,715,785			282,808,497
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 7)	285,333,869			284,715,785			286,127,897

(See notes to the consolidated financial statements)

8876

Gran Tierra Energy Inc.

Consolidated Balance Sheets

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)


	As at December 31,				As at December 31,
	2014		2013		2015			2014
ASSETS
Current Assets
Cash and cash equivalents	$	331,848	$	428,800	$	145,342		$	331,848
Restricted cash	1,836		1,478
Accounts receivable (Note 6)	83,227		49,703
Marketable securities (Note 13)	7,586		—
Inventory (Note 6)	17,298		13,725
Accounts receivable (Note 5)					29,217			83,227
Marketable securities (Note 12)					6,250			7,586
Inventory (Note 5)					19,056			17,298
Taxes receivable	15,843		9,980		28,635			15,843
Prepaids	6,000		6,450
Deferred tax assets (Note 10)	1,552		2,256
Other current assets					5,940			7,836
Total Current Assets	465,190		512,392		234,440			463,638

Oil and Gas Properties (using the full cost method of accounting)
Proved	801,075		794,069		469,589			801,075
Unproved	316,856		456,001		310,771			316,856
Total Oil and Gas Properties	1,117,931		1,250,070		780,360			1,117,931
Other capital assets	11,013		10,102		8,633			11,013
Total Property, Plant and Equipment (Note 7)	1,128,944		1,260,172
Total Property, Plant and Equipment (Note 6)					788,993			1,128,944

Other Long-Term Assets
Restricted cash	2,037		2,300
Deferred tax assets (Note 10)	601		1,407
Taxes receivable	9,684		18,535		8,276			9,684
Other long-term assets	5,013		7,163		11,828			9,203
Goodwill (Note 2)	102,581		102,581		102,581			102,581
Total Other Long-Term Assets	119,916		131,986		122,685			121,468
Total Assets	$	1,714,050	$	1,904,550	$	1,146,118		$	1,714,050
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable (Note 11)	$	112,401	$	72,400
Accrued liabilities (Note 11)	75,430		89,567
Foreign currency derivative (Note 13)	3,057		—
Accounts payable and accrued liabilities (Note 10)					$	70,778		$	187,831
Foreign currency derivative (Note 12)					—			3,057
Taxes payable	25,412		102,887		1,067			25,412
Deferred tax liabilities (Note 10)	1,040		1,193
Asset retirement obligation (Note 9)	8,026		518
Asset retirement obligation (Note 8)					2,146			8,026
Total Current Liabilities	225,366		266,565		73,991			224,326

Long-Term Liabilities
Deferred tax liabilities (Note 10)	175,324		177,082
Asset retirement obligation (Note 9)	27,786		21,455
Deferred tax liabilities (Note 9)					34,592			176,364
Asset retirement obligation (Note 8)					31,078			27,786
Other long-term liabilities	8,889		9,540		4,815			8,889
Total Long-Term Liabilities	211,999		208,077		70,485			213,039

Commitments and Contingencies (Note 12)
Commitments and Contingencies (Note 11)
Subsequent Events (Note 16)
Shareholders’ Equity
Common Stock (Note 8) (276,072,351 and 272,327,810 shares of Common Stock and 10,119,745 and 10,882,440 exchangeable shares, par value $0.001 per share, issued and outstanding as at December 31, 2014 and December 31, 2013, respectively)	10,190		10,187
Common Stock (Note 7) (273,442,799 and 276,072,351 shares of Common Stock and 8,572,066 and 10,119,745 exchangeable shares, par value $0.001 per share, issued and outstanding as at December 31, 2015 and December 31, 2014, respectively)					10,186			10,190
Additional paid in capital	1,026,873		1,008,760		1,019,863			1,026,873
Retained earnings	239,622		410,961
(Deficit) retained earnings					(28,407		)	239,622
Total Shareholders’ Equity	1,276,685		1,429,908		1,001,642			1,276,685
Total Liabilities and Shareholders’ Equity	$	1,714,050	$	1,904,550	$	1,146,118		$	1,714,050

(See notes to the consolidated financial statements)

8977

Gran Tierra Energy Inc.

Consolidated Statements of Cash Flows

(Thousands of U.S. Dollars)

Year Ended December 31,
2014 2013 2012
Operating Activities
Net income (loss) $ (171,339 ) $ 126,288
$ 99,659
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Loss from discontinued operations, net of income taxes (Note 3) 26,990
54,735
423
Depletion, depreciation, accretion and impairment 451,003
202,851
150,570
Deferred tax expense (recovery) (Note 10) 34,350
(28,865 ) 26,814
Non-cash stock-based compensation 5,451
8,002
10,999
Unrealized loss on financial instruments 9,383
—
—
Unrealized foreign exchange (gain) loss (38,441 ) (18,799 ) 17,150
Cash settlement of asset retirement obligation (Note 9) (796 ) (2,068 ) —
Other loss (Note 12) —
4,400
—
Other gain (Notes 10 and 12) (2,000 ) —
(9,336 )
Equity tax (3,283 ) (3,345 ) (3,534 )
Net change in assets and liabilities from operating activities of continuing operations

Accounts receivable and other long-term assets (34,473 ) 58,955
(46,764 )
Inventory (2,891 ) 14,168
(18,253 )
Prepaids 4
(2,458 ) (416 )
Accounts payable and accrued and other long-term liabilities 558
(8,754 ) (10,178 )
Taxes receivable and payable (61,064 ) 84,687
(88,253 )
Net cash provided by operating activities of continuing operations 213,452
489,797
128,881
  Net cash (used in) provided by operating activities of discontinued operations (4,792 ) 31,064
27,438
Net cash provided by operating activities 208,660
520,861
156,319

Investing Activities

(Increase) decrease in restricted cash (96 ) (1,590 ) 10,954
Additions to property, plant and equipment (347,027 ) (343,591 ) (238,205 )
Proceeds from oil and gas properties (Note 7) —
55,524
—
   Cash paid for acquisition (Note 4) —
—
(35,495 )
Net cash used in investing activities of continuing operations (347,123 ) (289,657 ) (262,746 )
Proceeds from sale of Argentina business unit, net of cash sold and transaction costs 42,755
—
—
  Net cash used in investing activities of discontinued operations (12,384 ) (18,799 ) (36,974 )
Net cash provided by (used in) investing activities of discontinued operations 30,371
(18,799 ) (36,974 )
Net cash used in investing activities (316,752 ) (308,456 ) (299,720 )

Financing Activities

Proceeds from issuance of shares of Common Stock (Note 8) 11,140
3,771
4,340
Net cash provided by financing activities 11,140
3,771
4,340

Net (decrease) increase in cash and cash equivalents (96,952 ) 216,176
(139,061 )
Cash and cash equivalents, beginning of year 428,800
212,624
351,685
Cash and cash equivalents, end of year $ 331,848
$ 428,800
$ 212,624

Supplemental cash flow disclosures:

Cash paid for income taxes $ 101,179
$ 51,183
$ 143,498

Non-cash investing activities:

Net liabilities related to property, plant and equipment, end of year $ 113,874
$ 75,580
$ 75,393
Acquisition of marketable securities as proceeds from sale of Argentina business unit (Note 3) $ 13,912
$ —
$ —



	Year Ended December 31,
	2015			2014			2013
Operating Activities
Net income (loss)	$	(268,029	)	$	(171,339	)	$	126,288
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations, net of income taxes (Note 3)	—			26,990			54,735
Depletion, depreciation and accretion	176,386			185,877			200,851
Asset impairment (Note 6)	323,918			265,126			2,000
Deferred tax (recovery) expense (Note 9)	(115,442		)	34,350			(28,865		)
Non-cash stock-based compensation	2,091			5,451			8,002
Financial instruments loss (Note 12)	2,027			4,722			—
Unrealized foreign exchange gain	(8,380		)	(30,941		)	(16,103		)
Cash settlement of foreign currency derivatives	(3,749		)	4,661			—
Cash settlement of asset retirement obligation (Note 8)	(6,217		)	(796		)	(2,068		)
Other loss (Note 11)	—			—			4,400
Other gain (Note 11)	(502		)	(2,000		)	—
Equity tax	—			(3,283		)	(3,345		)
Net change in assets and liabilities from operating activities of continuing operations (Note 15)	(39,798		)	(97,866		)	146,598
Net cash provided by operating activities of continuing operations	62,305			220,952			492,493
Net cash (used in) provided by operating activities of discontinued operations	—			(4,792		)	31,064
Net cash provided by operating activities	62,305			216,160			523,557

Investing Activities
Decrease (increase) in restricted cash	465			(96		)	(1,590		)
Additions to property, plant and equipment	(156,639		)	(391,526		)	(345,865		)
Changes in non-cash investing working capital	(76,844		)	44,499			2,274
Proceeds from oil and gas properties (Note 6)	—			—			55,524
Net cash used in investing activities of continuing operations	(233,018		)	(347,123		)	(289,657		)
Proceeds from sale of Argentina business unit, net of cash sold and transaction costs	—			42,755			—
Net cash used in investing activities of discontinued operations	—			(12,384		)	(18,799		)
Net cash provided by (used in) investing activities of discontinued operations	—			30,371			(18,799		)
Net cash used in investing activities	(233,018		)	(316,752		)	(308,456		)

Financing Activities
Repurchase of shares of Common Stock (Note 7)	(9,999		)	—			—
Proceeds from issuance of shares of Common Stock (Note 7)	722			11,140			3,771
Net cash (used in) provided by financing activities	(9,277		)	11,140			3,771

Foreign exchange loss on cash and cash equivalents	(6,516		)	(7,500		)	(2,696		)

Net (decrease) increase in cash and cash equivalents	(186,506		)	(96,952		)	216,176
Cash and cash equivalents, beginning of year	331,848			428,800			212,624
Cash and cash equivalents, end of year	$	145,342		$	331,848		$	428,800

Supplemental cash flow disclosures (Note 15)

(See notes to the consolidated financial statements)

9078

Gran Tierra Energy Inc.

Consolidated Statements of Shareholders’ Equity

(Thousands of U.S. Dollars)


	Year Ended December 31,								Year Ended December 31,
	2014			2013		2012			2015			2014			2013
Share Capital
Balance, beginning of year	$	10,187		$	7,986	$	7,510		$	10,190		$	10,187		$	7,986
Issue of shares of Common Stock	3			2,201		476
Issuance of Common Stock									—			3			2,201
Repurchase of Common Stock									(4		)				—
Balance, end of year	10,190			10,187		7,986			10,186			10,190			10,187

Additional Paid in Capital
Balance, beginning of year	1,008,760			998,772		980,014			1,026,873			1,008,760			998,772
Issue of shares of Common Stock	—			—		2,902
Exercise of warrants (Note 8)	—			—		1,590
Expiry of warrants (Note 8)	—			—		190
Exercise of stock options (Note 8)	11,137			1,570		960
Stock-based compensation (Note 8)	6,976			8,418		13,116
Exercise of stock options (Note 7)									722			11,137			1,570
Stock-based compensation (Note 7)									2,263			6,976			8,418
Repurchase of Common Stock (Note 7)									(9,995		)	—			—
Balance, end of year	1,026,873			1,008,760		998,772			1,019,863			1,026,873			1,008,760

Warrants
Balance, beginning of year	—			—		1,780
Exercise of warrants (Note 8)	—			—		(1,590		)
Expiry of warrants (Note 8)	—			—		(190		)
Balance, end of year	—			—		—

Retained Earnings
Retained Earnings (Deficit)
Balance, beginning of year	410,961			284,673		185,014			239,622			410,961			284,673
Net income (loss)	(171,339		)	126,288		99,659			(268,029		)	(171,339		)	126,288
Balance, end of year	239,622			410,961		284,673			(28,407		)	239,622			410,961

Total Shareholders’ Equity	$	1,276,685		$	1,429,908	$	1,291,431		$	1,001,642		$	1,276,685		$	1,429,908



Nevada		98-0479924
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

200, 150 13 Avenue S.W. Calgary, Alberta, Canada T2R 0V2
(Address of principal executive offices, including zip code)



Title of each class		Name of each exchange on which registered
Common Stock, par value $0.001 per share		NYSE MKT
		Toronto Stock Exchange



Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (do not check if a smaller reporting company)	Smaller reporting company o



		Page

PART I
~~Item 1.~~Items 1 and 2.	Business and Properties	75
Item 1A.	Risk Factors	3227
Item 1B.	Unresolved Staff Comments	47
~~Item 2.~~	~~Properties~~	4741
Item 3.	Legal Proceedings	4841
Item 4.	Mine Safety Disclosures	4843

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	5044
Item 6.	Selected Financial Data	5247
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	5449
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	8473
Item 8.	Financial Statements and Supplementary Data	8774
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~121~~108
Item 9A.	Controls and Procedures	~~121~~108
Item 9B.	Other Information	~~124~~111

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~124~~111
Item 11.	Executive Compensation	~~124~~111
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~124~~111
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~125~~112
Item 14.	Principal Accounting Fees and Services	~~125~~112

PART IV
Item 15.	Exhibits, Financial Statement Schedules	~~125~~112

SIGNATURES		~~126~~114
EXHIBIT INDEX		~~128~~116



bbl	barrel	Mcf	thousand cubic feet
Mbbl	thousand barrels	MMcf	million cubic feet
MMbbl	million barrels	Bcf	billion cubic feet
BOE	barrels of oil equivalent	~~MMBtu~~bopd	~~million British thermal units~~barrels of oil per day
MMBOE	million barrels of oil equivalent	NGL	natural gas liquids
BOEPD	barrels of oil equivalent per day	NAR	net after royalty
~~bopd~~	~~barrels of oil per day~~



ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Block and Field(s)	Basin	WI	Estimated Proved Reserves, NAR	2015 Average Production NAR, BOEPD	Number of Productive Wells at December 31, 2015, Net	End of Production Phase	Acres, Net⁽¹⁾
Chaza - Costayaco and Moqueta Fields	Putumayo	100% operated	29,375	16,601	28.0	2033 for Costayaco and 2037 for Moqueta	46,676
Guayuyaco - Guayuyaco and Juanambu Fields	Putumayo	70% operated	1,890	727	3.8	2030	36,656
Garibay (50% WI) - Jilguero Field (38.5% WI)	Llanos	50% non-operated	753	739	1.9	2037	19,460
Llanos-22 - Ramiriqui Field	Llanos	45% non-operated	1,672	810	0.9	2038	19,075
11 Other Blocks	Putumayo, Cauca, Catatumbo or Sinu	See below	—	95	—	—	2,652,763
Gran Tierra as at December 31, 2015⁽¹⁾			33,690	18,972	34.6		2,774,630
Combined Petroamerica and PGC⁽²⁾			3,947	3,360	7.6		940,708
Pro forma Gran Tierra as at December 31, 2015⁽³⁾			37,637	22,332	42.2		3,715,338



Block	Acres, Gross and Net
Block 95	853,210
Block 123	2,323,831
Block 129	1,167,409
Block 107	623,504
Block 133	764,320
	5,732,274



	Oil	Natural Gas	Oil and Natural Gas
Reserves Category	(Mbbl)	(MMcf)	(MBOE)
Proved
Developed
Colombia	28,513	1,346	28,737
Brazil	2,303	1,368	2,531
Total proved developed reserves	30,816	2,714	31,268
Undeveloped
Colombia	4,873	477	4,953
Brazil	2,420	1,437	2,659
Total proved undeveloped reserves	7,293	1,914	7,612
Total proved reserves	38,109	4,628	38,880

Probable
Developed
Colombia	7,354	514	7,440
Brazil	651	386	715
Total probable developed reserves	8,005	900	8,155
Undeveloped
Colombia	5,319	557	5,412
Brazil	1,952	1,159	2,145
Total probable undeveloped reserves	7,271	1,716	7,557
Total probable reserves	15,276	2,616	15,712

Possible
Developed
Colombia	6,044	530	6,132
Brazil	563	334	619
Total possible developed reserves	6,607	864	6,751
Undeveloped
Colombia	3,860	508	3,945
Brazil	1,688	1,002	1,855
Total possible undeveloped reserves	5,548	1,510	5,800
Total possible reserves	12,155	2,374	12,551


Oil and NGLs (USD/bbl) - Colombia			$	43.96
Natural Gas (USD/Mcf) - Colombia			$	3.55
Light/Medium Oil (USD/bbl) - Brazil	$	84.63	$	40.57
Natural Gas (USD/Mcf) - Brazil	$	4.69	$	1.47
Oil and NGLs (USD/bbl) - Colombia	$	88.63
Natural Gas (USD/Mcf) - Colombia	$	4.43



	~~Oil Equivalent~~ ~~(MMBOE)~~
~~Balance, December 31, 2013~~	~~8.4~~
~~Converted to proved producing~~	~~(7.1~~	)
~~Discoveries and extensions~~	~~4.0~~
~~Sale~~	~~(1.3~~	)
~~Improved recovery~~	~~0.7~~
~~Technical revisions~~	~~3.0~~
~~Balance, December 31, 2014~~	~~7.7~~



	Oil Equivalent (MMBOE)
Balance, December 31, 2014	$	7.7
Converted to proved producing	(1.3		)
Discoveries and extensions	0.6
Technical revisions	0.6
Balance, December 31, 2015	$	7.6



	Productive		Dry		Still in Progress
	Gross	Net	Gross	Net	Gross	Net
Colombia	1.00	1.00			3.00	3.00
Brazil	—	—	—	—	—	—
Peru	—	—	1.00	1.00	—	—
	1.00	1.00	1.00	1.00	3.00	3.00



	Oil Wells		Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Colombia (1)	54.0	43.75	—	—	54.0	43.8
Brazil (2)	3.0	3.0	—	—	3.0	3.0
Peru	1.0	1.0	—	—	1.0	1.0
	58.0	47.8	—	—	58.0	47.8


	Developed		Undeveloped		Total		Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Colombia (1)	380,277	309,093	3,731,375	3,205,997	4,111,652	3,515,090	180,349	121,867	3,216,195	2,652,763	3,396,544	2,774,630
Brazil	5,786	5,786	41,947	41,947	47,733	47,733	1,511	1,511	46,223	46,223	47,734	47,734
Peru	—	—	5,732,274	5,732,274	5,732,274	5,732,274	—	—	5,732,274	5,732,274	5,732,274	5,732,274
	386,063	314,879	9,505,596	8,980,218	9,891,659	9,295,097
Gran Tierra as at December 31, 2015⁽¹⁾							181,860	123,378	8,994,692	8,431,260	9,176,552	8,554,638
Combined Petroamerica and PGC⁽²⁾							1,514,477	386,108	794,545	554,600	2,309,022	940,708
Pro forma as at December 31, 2015⁽³⁾							1,696,337	509,486	9,789,237	8,985,860	11,485,574	9,495,346



	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share⁽²⁾	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs⁽³⁾
July 1-31, 2015	—	—	—	13,831,866
August 1-31, 2015	2,575,996	2.18	2,575,996	11,255,870
September 1-30, 2015	424,800	2.30	424,800	10,831,070
October 1-31, 2015	485,100	2.24	485,100	10,345,970
November 1-30, 2015	—	—	—	10,345,970
December 1-31, 2015	1,081,240	2.12	1,081,240	9,264,730
Total	4,567,136	2.19	4,567,136	9,264,730


Statement of Operations Data
	Year Ended December 31,															Year Ended December 31,
	2014			2013			2012			2011			2010			2015			2014			2013			2012			2011
Oil and natural gas sales	$	559,398		$	646,955		$	503,467		$	548,175		$	359,302		$	276,011		$	559,398		646,955			$	503,467		$	548,175
Interest income	2,856			2,174			1,709			1,124			1,148
	562,254			649,129			505,176			549,299			360,450

Operating expenses	113,949			110,172			92,207			59,421			50,638			75,565			89,753			91,223			65,562			51,690
DD&A expenses	451,003			202,851			150,570			185,696			134,156
Transportation																40,204			24,196			18,949			26,645			7,731
Depletion, depreciation and accretion																176,386			185,877			200,851			130,370			143,696
Asset impairment																323,918			265,126			2,000			20,200			42,000
G&A expenses	51,249			41,115			46,659			52,344			37,373			32,353			51,249			41,115			46,659			52,344
Severance expenses																8,990			—			—			—			—
Equity tax																3,769			—			—			—			8,271
Foreign exchange (gain) loss																(17,242		)	(39,535		)	(18,693		)	28,727			(255		)
Financial instruments loss (gain)	4,722			—			—			(1,354		)	(43		)	2,027			4,722			—			—			(1,354		)
Other loss	—			4,400			—			—			—			—			—			4,400			—			—
Other gain	(2,000		)	—			(9,336		)	—			—			(502		)	(2,000		)	—			(9,336		)	—
Equity tax	—			—			—			8,271			—
Gain on acquisition	—			—			—			(21,699		)	—			—			—			—			—			(21,699		)
Foreign exchange (gain) loss	(39,535		)	(18,693		)	28,727			(255		)	16,672
	579,388			339,845			308,827			282,424			238,796			645,468			579,388			339,845			308,827			282,424

Interest income																1,369			2,856			2,174			1,709			1,124

(Loss) income from continuing operations before income taxes	(17,134		)	309,284			196,349			266,875			121,654			(368,088		)	(17,134		)	309,284			196,349			266,875
Income tax expense	(127,215		)	(128,261		)	(96,267		)	(115,290		)	(51,548		)

Current income tax (expense) recovery																(15,383		)	(92,865		)	(157,126		)	(69,453		)	(134,018		)
Deferred income tax recovery (expense)																115,442			(34,350		)	28,865			(26,814		)	18,728
																100,059			(127,215		)	(128,261		)	(96,267		)	(115,290		)

(Loss) income from continuing operations	(144,349		)	181,023			100,082			151,585			70,106			(268,029		)	(144,349		)	181,023			100,082			151,585
Loss from discontinued operations, net of income taxes	(26,990		)	(54,735		)	(423		)	(24,668		)	(32,934		)	—			(26,990		)	(54,735		)	(423		)	(24,668		)
Net income (loss)	$	(171,339	)	$	126,288		$	99,659		$	126,917		$	37,172		$	(268,029	)	$	(171,339	)	126,288			$	99,659		$	126,917

INCOME (LOSS) PER SHARE
BASIC
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.51	)	$	0.64		$	0.35		$	0.55		$	0.28		$	(0.94	)	$	(0.51	)	$	0.64		$	0.35		$	0.55
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	(0.09		)	(0.19		)	0.00			(0.09		)	(0.13		)	—			(0.09		)	(0.19		)	—			(0.09		)
NET INCOME (LOSS)	$	(0.60	)	$	0.45		$	0.35		$	0.46		$	0.15		$	(0.94	)	$	(0.60	)	$	0.45		$	0.35		$	0.46
DILUTED
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.51	)	$	0.63		$	0.35		$	0.54		$	0.27		$	(0.94	)	$	(0.51	)	$	0.63		$	0.35		$	0.54
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	(0.09		)	(0.19		)	0.00			(0.09		)	(0.13		)
NET INCOME (LOSS)	$	(0.60	)	$	0.44		$	0.35		$	0.45		$	0.14



	Year Ended December 31,
	2014			% Change		2013			% Change		2012
Estimated Proved Oil and Gas Reserves, NAR, at December 31 (MMBOE) (5)	37.0			(12	)	42.1			4		40.6

Estimated Probable Oil and Gas Reserves, NAR, at December 31 (MMBOE) (5) (6)	13.5			(81	)	69.8			347		15.6

Estimated Possible Oil and Gas Reserves, NAR, at December 31 (MMBOE) (5) (6)	15.4			(79	)	72.0			139		30.1

Production (BOEPD) (1) (2)	18,523			(4	)	19,239			43		13,423

Prices Realized - per BOE (1)	$	82.74		(10	)	$	92.13		(10	)	$	102.48

Revenue and Other Income ($000s) (1)	$	562,254		(13	)	$	649,129		28		$	505,176

(Loss) Income from Continuing Operations ($000s) (1)	$	(144,349	)	(180	)	$	181,023		81		$	100,082
Loss from Discontinued Operations, Net of Income Taxes ($000s)	(26,990		)	(51	)	(54,735		)	—		(423		)
Net Income (Loss) ($000s)	$	(171,339	)	(236	)	$	126,288		27		$	99,659

Income (Loss) Per Share - Basic
(Loss) Income from Continuing Operations (1)	$	(0.51	)	(180	)	$	0.64		83		$	0.35
Loss from Discontinued Operations, Net of Income Taxes	(0.09		)	(53	)	(0.19		)	—		0.00
Net Income (Loss)	$	(0.60	)	(233	)	$	0.45		29		$	0.35

Income (Loss) Per Share - Diluted
(Loss) Income from Continuing Operations (1)	$	(0.51	)	(181	)	$	0.63		80		$	0.35
Loss from Discontinued Operations, Net of Income Taxes	(0.09		)	(53	)	(0.19		)	—		0.00
Net Income (Loss)	$	(0.60	)	(236	)	$	0.44		26		$	0.35

Funds Flow From Continuing Operations ($000s) (1)(3)	$	311,318		(9	)	$	343,199		17		$	292,745

Net Capital Expenditures for Continuing Operations ($000s) (1) (4)	$	416,232		41		$	295,315		8		$	272,523



	Year Ended December 31,
EBITDA - Non-GAAP Measure ($000s)	2015			2014			2013
Net income (loss)	$	(268,029	)	$	(171,339	)	$	126,288
Adjustments to reconcile net income (loss) to EBITDA
Loss from discontinued operations, net of income taxes	—			26,990			54,735
DD&A expenses	176,386			185,877			200,851
Asset Impairment	323,918			265,126			2,000
Income tax (recovery) expense	(100,059		)	127,215			128,261
EBITDA	$	132,216		$	433,869		$	512,135
Foreign exchange gain	(17,242		)	(39,535		)	(18,693		)
Adjusted EBITDA	$	114,974		$	394,334		$	493,442


	Year Ended December 31,									Year Ended December 31,
Funds Flow From Continuing Operations - Non-GAAP Measure ($000s)	2014			2013			2012			2015			2014			2013
Net income (loss)	$	(171,339	)	$	126,288		$	99,659		$	(268,029	)	$	(171,339	)	$	126,288
Adjustments to reconcile net income (loss) to funds flow from continuing operations
Loss from discontinued operations, net of income taxes	26,990			54,735			423			—			26,990			54,735
DD&A expenses	451,003			202,851			150,570			176,386			185,877			200,851
Deferred tax expense (recovery)	34,350			(28,865		)	26,814
Asset impairment										323,918			265,126			2,000
Deferred tax (recovery) expense										(115,442		)	34,350			(28,865		)
Non-cash stock-based compensation	5,451			8,002			10,999			2,091			5,451			8,002
Unrealized loss on financial instruments	9,383			—			—
Unrealized foreign exchange (gain) loss	(38,441		)	(18,799		)	17,150
Cash settlement of asset retirement obligation	(796		)	(2,068		)	—
Financial instruments loss										2,027			4,722			—
Unrealized foreign exchange gain										(8,380		)	(30,941		)	(16,103		)
Cash settlement of foreign currency derivatives										(3,749		)	4,661			—
Other loss	—			4,400			—			—			—			4,400
Other gain	(2,000		)	—			(9,336		)	(502		)	(2,000		)	—
Equity tax	(3,283		)	(3,345		)	(3,534		)	—			(3,283		)	(3,345		)
Funds flow from continuing operations	$	311,318		$	343,199		$	292,745		$	108,320		$	319,614		$	347,963



Oil and natural gas sales	$	41.41		(50	)	$	82.74		(10	)	$	92.13

Operating expenses	11.34			(15	)	13.28			2		12.99
Transportation expenses	6.03			68		3.58			33		2.70
DD&A expenses	26.47			(4	)	27.49			(4	)	28.60
Asset impairment	48.60			24		39.21			—		0.29
G&A expenses	4.85			(36	)	7.58			29		5.86
Severance expenses	1.35			—		—			—		—
Equity tax	0.57			—		—			—		—
Foreign exchange gain	(2.59)			56		(5.85)			(120	)	(2.66)
Financial instruments loss	0.30			(57	)	0.70			—		—
Other loss	—			—		—			(100	)	0.63
Other gain	(0.08		)	73		(0.30		)	—		—
	96.84			13		85.69			77		48.41

Interest income	0.21			(50	)	0.42			35		0.31

(Loss) income from continuing operations before income taxes	(55.22		)	(2,083	)	(2.53		)	(106	)	44.03

Current income tax expense	(2.31)			(83	)	(13.74)			(39	)	(22.38)
Deferred income tax recovery (expense)	17.32			(441	)	(5.08)			224		4.11
	15.01			(180	)	(18.82)			(3	)	(18.27)

(Loss) income from continuing operations	$	(40.21	)	(88	)	$	(21.35	)	(183	)	$	25.76



	Year Ended December 31,
Average Daily Volumes (BOEPD) - Colombia	2015		2014		2013
Working Interest Production Before Royalties	22,794		24,128		24,811
Royalties	(3,822	)	(5,749	)	(6,460	)
Production NAR	18,972		18,379		18,351
(Increase) Decrease in Inventory	(1,231	)	(760	)	233
Sales	17,741		17,619		18,584

	Year Ended December 31,
Average Daily Volumes (BOEPD) - Brazil	2015		2014		2013
Working Interest Production Before Royalties	607		1,054		827
Royalties	(90	)	(150	)	(107	)
Production NAR	517		904		720
(Increase) Decrease in Inventory	2		—		(65	)
Sales	519		904		655

	Year Ended December 31,
Average Daily Volumes (BOEPD) - Total	2015		2014		2013
Working Interest Production Before Royalties	23,401		25,182		25,638
Royalties	(3,912	)	(5,899	)	(6,567	)
Production NAR	19,489		19,283		19,071
(Increase) Decrease in Inventory	(1,229	)	(760	)	168
Sales	18,260		18,523		19,239



	Year Ended December 31, 2015				Year Ended December 31, 2014
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE		DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	167,701	$	25.90	$	174,063	$	27.07
Brazil	6,183		32.66		9,932		30.09
Peru	789		—		690		—
Corporate	1,713		—		1,192		—
	$	176,386	$	26.47	$	185,877	$	27.49

	Year Ended December 31, 2013
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	184,697	$	27.23
Brazil	14,761		61.75
Peru	362		—
Corporate	1,031		—
	$	200,851	$	28.60


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



	Year Ended December 31,
(Millions of U.S. Dollars)	2014		2013		2012
Drilling and completions	$	117.5	$	107.1	$	103.1
Facilities and equipment	28.4		29.4		26.3
G&G	52.0		40.0		14.5
Other	17.0		13.5		9.4
	$	214.9	$	190.0	$	153.3



	Year Ended December 31,
	2014 (1)			% Change		2013 (2)			% Change		2012 (2)
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	31,938		(57	)	$	73,495		(8	)	$	79,642
Interest income	47			(95	)	1,019			176		369
	31,985			(57	)	74,514			(7	)	80,011

Operating expenses	14,612			(62	)	38,886			19		32,696
DD&A expenses	13,684			(79	)	64,295			104		31,466
G&A expenses	5,579			(55	)	12,284			—		12,224
Foreign exchange loss	4,362			(33	)	6,497			149		2,610
	38,237			(69	)	121,962			54		78,996

(Loss) income from discontinued operations before income taxes	$	(6,252	)	(87	)	$	(47,448	)	—		$	1,015

Production (3)

Oil and NGL's, bbl	377,795			(57	)	882,110			(16	)	1,047,265
Natural gas, Mcf	713,263			(47	)	1,338,110			(1	)	1,346,368
Total production, BOE	496,672			(55	)	1,105,128			(13	)	1,271,660

Average Prices

Oil and NGL's per bbl	$	75.98		(1	)	$	77.12		8		$	71.12
Natural gas per Mcf	$	4.53		11		$	4.08		7		$	3.83

Segmented Results of Operations per BOE

Oil and natural gas sales	$	64.30		(3	)	$	66.50		6		$	62.63
Interest income	0.09			(90	)	0.92			217		0.29
	64.39			(4	)	67.42			7		62.92

Operating expenses	29.42			(16	)	35.19			37		25.71
DD&A expenses	27.55			(53	)	58.18			135		24.74
G&A expenses	11.23			1		11.12			16		9.61
Foreign exchange loss	8.78			49		5.88			187		2.05
	76.98			(30	)	110.37			78		62.11

(Loss) income from discontinued operations before income taxes	$	(12.59	)	(71	)	$	(42.95	)	—		$	0.81


	Total		Less than 1 Year		1 to 3 Years		4 to 5 Years		More than 5 Years
Contractual Obligations											Total		Less than 1 Year		1 to 3 Years		4 to 5 Years		More than 5 Years
(Thousands of U.S. Dollars)
Oil transportation services	$	22,252	$	3,640	$	7,280	$	7,280	$	4,052	$	18,441	$	3,650	$	7,280	$	7,280	$	231
Drilling and G&G	831		588		243		—		—
Drilling, completions and seismic											7,572		2,918		4,654		—		—
Operating leases	9,637		2,631		5,241		1,765		—		7,140		3,103		4,036		1		—
Software and telecommunication	620		260		360		—		—		479		351		128		—		—
	$	33,340	$	7,119	$	13,124	$	9,045	$	4,052
Total											$	33,632	$	10,022	$	16,098	$	7,281	$	231



	As at
(Thousands of U.S. Dollars)	December 31, 2013
Current assets (1)	$	39,125
Property, plant and equipment	94,446
Other long-term assets	1,839
	$	135,410

Current liabilities	$	37,612
Long-term liabilities	9,755
	$	47,367



(Thousands of U.S. Dollars)
Consideration Transferred:
Cash	$	35,495
Fair value of contingent consideration payable	1,061
	$	36,556

Allocation of Consideration Transferred:
Oil and gas properties
Proved	$	24,107
Unproved	12,859
Asset retirement obligation	(410		)
	$	36,556



	Year Ended December 31, 2015
(Thousands of U.S. Dollars, except per unit of sales amounts)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	269,035		$	—		$	6,976		$	—		$	276,011
Interest income	294			2			218			855			1,369
DD&A expenses	167,701			789			6,183			1,713			176,386
DD&A - per unit of sales	25.90			—			32.66			—			26.47
Asset impairment	235,069			41,916			46,933			—			323,918
General and administrative	9,805			3,800			2,708			16,040			32,353
Loss from continuing operations before income taxes	(238,463		)	(51,675		)	(54,968		)	(22,982		)	(368,088		)
Segment capital expenditures	87,723			50,419			19,989			1,095			159,226
	Year Ended December 31, 2014
(Thousands of U.S. Dollars, except per unit of sales amounts)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	532,196		$	—		$	27,202		$	—		$	559,398
Interest income	569			1			1,604			682			2,856
DD&A expenses	174,063			690			9,932			1,192			185,877
DD&A - per unit of sales	27.07			—			30.09			—			27.49
Asset impairment	—			265,126			—			—			265,126
General and administrative	19,431			6,448			3,698			21,672			51,249
Income (loss) from continuing operations before income taxes	279,924			(274,207		)	5,921			(28,772		)	(17,134		)
Segment capital expenditures	214,928			174,158			24,278			2,868			416,232
	Year Ended December 31, 2013
(Thousands of U.S. Dollars, except per unit of sales amounts)	Colombia			Peru			Brazil			All Other			Total
Oil and natural gas sales	$	624,410		$	—		$	22,545		$	—		$	646,955
Interest income	623			27			909			615			2,174
DD&A expenses	184,697			362			14,761			1,031			200,851
DD&A - per unit of sales	27.23			—			61.75			—			28.60
Asset impairment	—			—			2,000			—			2,000
General and administrative	16,996			5,524			2,231			16,364			41,115
Income (loss) from continuing operations before income taxes	336,179			(7,067		)	(2,650		)	(17,178		)	309,284
Segment capital expenditures (1)	188,547			82,954			23,039			775			295,315



	As at December 31, 2015
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	574,351	$	95,069	$	115,552	$	4,021	$	788,993
Goodwill	102,581		—		—		—		$	102,581
All other assets	93,479		21,111		2,236		137,718		$	254,544
Total Assets	$	770,411	$	116,180	$	117,788	$	141,739	$	1,146,118

	As at December 31, 2014
(Thousands of U.S. Dollars)	Colombia		Peru		Brazil		All Other		Total
Property, plant and equipment	$	888,822	$	87,028	$	148,457	$	4,637	$	1,128,944
Goodwill	102,581		—		—		—		$	102,581
All other assets	157,549		40,613		14,724		269,639		$	482,525
Total Assets	$	1,148,952	$	127,641	$	163,181	$	274,276	$	1,714,050


	As at December 31, 2014							As at December 31, 2013							As at December 31,
(Thousands of U.S. Dollars)	Cost		Accumulated depletion, depreciation and impairment			Net book value		Cost		Accumulated depletion, depreciation and impairment			Net book value		2015			2014
Oil and natural gas properties
Proved	$	1,876,371	$	(1,075,296	)	$	801,075	$	1,799,544	$	(1,005,475	)	$	794,069	$	1,998,330		$	1,876,371
Unproved	316,856		—			316,856		456,001		—			456,001		310,771			316,856
	2,193,227		(1,075,296		)	1,117,931		2,255,545		(1,005,475		)	1,250,070		2,309,101			2,193,227
Furniture and fixtures and leasehold improvements	11,177		(8,421		)	2,756		8,919		(6,568		)	2,351
Computer equipment	14,323		(7,461		)	6,862		14,786		(7,605		)	7,181
Automobiles	1,787		(392		)	1,395		1,381		(811		)	570
Total Property, Plant and Equipment	$	2,220,514	$	(1,091,570	)	$	1,128,944	$	2,280,631	$	(1,020,459	)	$	1,260,172
Other															28,342			27,287
															2,337,443			2,220,514
Accumulated depletion, depreciation and impairment															(1,548,450		)	(1,091,570		)
															$	788,993		$	1,128,944


	Costs Incurred in										Costs Incurred in
(Thousands of U.S. Dollars)	2014		2013		2012		Prior to 2012		Total		2015		2014		2013		Prior to 2013			Total
Acquisition costs - Colombia	$	—	$	—	$	—	$	75,691	$	75,691	$	—	$	—	$	—	$	67,597		$	67,597
Acquisition costs - Peru	—		—		—		21,147		21,147		—		—		—		21,147			21,147
Acquisition costs - Brazil	—		—		12,859		22,666		35,525		—		—		—		35,525			35,525
Exploration costs - Colombia	39,114		28,404		9,319		17,946		94,783		11,151		35,952		20,103		12,697			79,903
Exploration costs - Peru	25,341		9,849		23,312		6,018		64,520		8,515		31,750		7,301		25,469			73,035
Exploration costs - Brazil	9,126		10,772		2,644		2,648		25,190		10,639		8,911		14,779		(765		)	33,564
Total oil and natural gas properties not subject to depletion	$	73,581	$	49,025	$	48,134	$	146,116	$	316,856	$	30,305	$	76,613	$	42,183	$	161,670		$	310,771



	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2014	276,072,351		5,595,118		4,524,627
Options exercised	390,000		—		—
Shares repurchased and canceled	(4,567,136	)	—		—
Exchange of exchangeable shares	1,547,595		(661,857	)	(885,738	)
Shares canceled	(11	)	(84	)	—
Balance, December 31, 2015	273,442,799		4,933,177		3,638,889