GRAN TIERRA ENERGY INC. - Annual Report: 2017 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2017



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

For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)



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

900, 520 - 3 Avenue SW Calgary, Alberta Canada T2P 0R3
(Address of principal executive offices, including zip code)

(403) 265-3221

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



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

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $0.9 billion.

On February 22, 2018, the following numbers of shares of the registrant’s capital stock were outstanding: 385,394,642 shares of the registrant’s Common Stock, $0.001 par value; one share of Special A Voting Stock, $0.001 par value, representing 1,688,889 shares of Gran Tierra Goldstrike Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock; and one share of Special B Voting Stock, $0.001 par value, representing 4,219,176 shares of Gran Tierra Exchangeco Inc., which are exchangeable on a 1-for-1 basis into the registrant’s Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this report, to the extent not set forth herein, is incorporated by reference from the registrant’s definitive proxy statement relating to the 2018 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2017.

Gran Tierra Energy Inc.

Annual Report on Form 10-K

Year Ended December 31, 2017

Table of Contents



		Page

PART I
Items 1 and 2.	Business and Properties	5
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	23
Item 3.	Legal Proceedings	23
Item 4.	Mine Safety Disclosures	23

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	28
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	91
Item 9A.	Controls and Procedures	92
Item 9B.	Other Information	94

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	94
Item 11.	Executive Compensation	94
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	94
Item 13.	Certain Relationships and Related Transactions, and Director Independence	95
Item 14.	Principal Accounting Fees and Services	95

PART IV
Item 15.	Exhibits, Financial Statement Schedules	95
Item 16.	Form 10-K Summary	101

SIGNATURES		101

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Annual Report on Form 10-K regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations, covenant compliance, capital spending plans and those statements preceded by, followed by or that otherwise include the words “believe”, “expect”, “anticipate”, “intend”, “estimate”, “project”, “target”, “goal”, “plan”, “budget”, “objective”, “should”, or similar expressions or variations on these expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct or that, even if correct, intervening circumstances will not occur to cause actual results to be different than expected. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, those set out in Part I, Item 1A. “Risk Factors” in this Annual Report on Form 10-K. The information included herein is given as of the filing date of this Annual Report on Form 10-K with the Securities and Exchange Commission (“SEC”) and, except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Annual Report on Form 10-K to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based.

GLOSSARY OF OIL AND GAS TERMS

In this report, the abbreviations set forth below have the following meanings:



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	bopd	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

Sales volumes represent production NAR adjusted for inventory changes and losses. Our oil and gas reserves are reported NAR. Our production is also reported NAR, except as otherwise specifically noted as “working interest production before royalties.” NGL volumes are converted to BOE on a one-to-one basis with oil. Gas volumes are converted to BOE at the rate of 6 Mcf of gas per bbl of oil, based upon the approximate relative energy content of gas and oil. The rate is not necessarily indicative of the relationship between oil and gas prices. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Below are explanations of some commonly used terms in the oil and gas business and in this report.

Developed acres. The number of acres that are allocated or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. Exploratory or development well that does not produce oil or gas in commercial quantities.

Exploitation activities. The process of the recovery of fluids from reservoirs and drilling and development of oil and gas reserves.

Exploration well. An exploration well is a well drilled to find a new field or new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells in which we own a working interest.

Net acres or net wells. The sum of the fractional working interests we own in gross acres or gross wells expressed as whole numbers and fractions of whole numbers.

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. The SEC provides a complete definition of possible reserves in Rule 4-10(a)(17) of Regulation S-X.

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered. The SEC provides a complete definition of probable reserves in Rule 4-10(a)(18) of Regulation S-X.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves. In general, reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

Proved reserves. 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

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

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

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

Proved undeveloped reserves. In general, reserves 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.

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.

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.

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

Items 1 and 2. Business and Properties

General

Gran Tierra Energy Inc., together with its subsidiaries (“Gran Tierra”, “us”, “our”, or “we”), is a company focused on oil and gas exploration and production in Colombia. Our Colombian properties represented 100% of our proved reserves NAR at December 31, 2017. For the year ended December 31, 2017, 98% (year ended December 31, 2016 - 97%; year ended December 31, 2015 - 97%) of our revenue and other income was generated in Colombia.

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. We sold our Argentina business unit in 2014. In 2016, we completed acquisitions of Petroamerica Oil Corp. (“Petroamerica”), PetroGranada Colombia Limited (“PGC”) and PetroLatina Energy Limited (“PetroLatina”). During 2017, we completed the sale of our assets in Brazil and Peru.

All dollar ($) amounts referred to in this Annual Report on Form 10-K are United States (U.S.) dollars, unless otherwise indicated.

2017 Overview

Acquisitions and Dispositions

On April 27, 2017, we acquired an operated 100% working interest (“WI”) in the Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin in Colombia for cash consideration of $30.4 million.

On June 30, 2017, we completed the sale of our Brazil business unit for a purchase price of $35.0 million, which, after certain final closing adjustments, resulted in cash consideration of approximately $36.8 million.

On December 18, 2017, we completed the sale of our Peru business unit. Pursuant to the divestiture, Sterling Resources Ltd. (“Sterling”) acquired all of the issued and outstanding shares in our indirect, wholly owned subsidiary that indirectly held all of our Peruvian assets for aggregate consideration of $33.5 million, comprising approximately 187.3 million common shares of Sterling and an estimated cash-settled working capital adjustment of $0.4 million. Additionally, in connection with the divestiture, we purchased $11.0 million of subscription receipts which were exchangeable for common shares of PetroTal Ltd. and subsequently exchanged them for approximately 58.9 million common shares of Sterling. After giving effect to the divestiture, we directly and indirectly hold approximately 246.2 million common shares representing approximately 46% of Sterling's issued and outstanding common shares.

2017 Operational Highlights

In the year ended December 31, 2017, we incurred capital expenditures of $251.0 million, including $242.6 million, or 97%, in Colombia. In Colombia, we drilled 4 exploration and 21 development wells, including 2 service wells.

We drilled exploration wells in the Putumayo-1 Block (Vonu-1), Putumayo-7 Block (Confianza-1), Putumayo-4 Block (Siriri-1) and Midas Block (Ayombero-1) Two of these wells are currently on production (Vonu-1 and Confianza-1) and we are currently evaluating Siriri and testing Ayombero.

Development wells were drilled in the Midas Block (Acordionero-9, 10i, 11, 12, 13, 14i, 15, 16, 17, 18, 20, 21 and Mochuelo), Suroriente Block (Cohembi-19, 20, 21, 22), Chaza Block (Costayaco-28, 29 and 30) and Guayuyaco Block (Juanambu-2). Two of these wells were water injection wells (Acordionero-10i and 14i).

We acquired and processed new 3-D seismic in the Cumplidor and Northwest areas in the Putumayo-7 Block. Two walkaway vertical seismic profiles were acquired and processed in the Acordionero Field. We re-processed 2-D and 3-D seismic in the Llanos Basin (Garibay-El Porton area), Middle Magdalena Basin (Acordionero, Los Angeles, Midas Norte areas) and Putumayo Basin (Cohembi, Moqueta, Costayaco). Minor re-processing was done for evaluations in Mexico.

We also continued facilities work at the Acordionero Field on the Midas Block and the Moqueta Field on the Chaza Block.

2018 Outlook

Colombia remains our focus and represents 100% of the 2018 capital program. In December 2017, we announced our 2018 capital budget. We expect the following ranges for our 2018 capital budget:



	Number of Wells (Gross)	Number of Wells (Net)	2018 Capital Budget ($ million)
Colombia
Development	19-21	18-20	100-105
Exploration	8-11	7-10	80-90
Facilities	—	—	50-55
Seismic and Studies	—	—	20
	27-32	25-30	250-270

Based on the midpoint of the guidance, the capital budget is forecasted to be approximately 60% directed to development and 40% to exploration. Between 30% and 35% of the 2018 capital program is expected to be directed to facilities, with approximately 75% of this investment expected to be dedicated to the ongoing facilities expansion at the Acordionero Field.

We expect our 2018 capital program to be fully funded by cash flows from operations.

Senior Notes Offering

On February 15, 2018, through our indirect wholly owned subsidiary, Gran Tierra Energy International Holdings Ltd., we issued $300 million aggregate principal amount of 6.25% Senior Notes due 2025 in a private placement transaction. The notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Business Strategy

Our strategy is to profitably grow our portfolio of exploration, development and production opportunities in Colombia. We are taking steps to grow cash flows from existing assets by developing reserves and growing reserves through enhanced oil recovery (“EOR”) techniques. Starting in 2017, we have consolidated sufficient exploration opportunities to commence a three to five year continuous exploration program which we expect will be fully funded through the reinvestment of cash flows from operations and leverage of our financial strength.

Oil and Gas Properties - Colombia

Acquisitions and Farm-ins

On April 27, 2017, we acquired an operated 100% WI in the Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin for cash consideration of $30.4 million.

On November 27, 2017, we entered into two farm-in agreements to acquire, subject to approval from the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”), additional WIs in the Alea 1848-A and 1947-C Blocks in the Putumayo Basin. Under the terms of the agreements, we will increase our position to 75% WI in each of these blocks and will carry the farmor on current contract phase obligations, to a combined maximum of $4.8 million. The applications for approval to be submitted to the ANH will include the appointment of Gran Tierra as operator of these blocks. During 2017, we relinquished our working interest in the Arjona Block.

Excluding blocks subject to relinquishment, we have interests in 30 blocks in Colombia and are the operator on 23 of these blocks.

Exploration Blocks & Commitments

The following table provides a summary of our exploration commitments for certain blocks as at December 31, 2017:



Basin	Block	Current Phase	Remaining Commitments, Current Phase
Putumayo	Alea 1848-A	3 & 4	70 km 2D seismic, 1 exploration well
Putumayo	Alea 1947-C	2*	1 exploration well
Putumayo	PPN	1*	52 km 2D seismic
Putumayo	PPS	2 & 3*	2 km of 2D seismic, 1 exploration well
Putumayo	PUT-1	2	2 exploration wells
Putumayo	PUT-2	2	3 exploration wells
Putumayo	PUT-4	1	1 exploration well
Putumayo	PUT-7	1	1 exploration well
Putumayo	PUT-10	1*	73 km 2D seismic, 2 exploration wells
Llanos	El Porton	5*	1 exploration well
Llanos	LLA-1	1**	97.5 km² 3D seismic, 1 exploration well
Llanos	LLA-10	1*	1 exploration well
Llanos	LLA-22	1 & 2*	85 km² 3D seismic, 1 exploration well
Llanos	LLA-53	1*	89 km² 3D seismic, 2 exploration wells (approval requested to transfer commitments to PUT4- and PUT-7)
Llanos	LLA-70	1**	163 km² 3D seismic, 1 exploration well
Caguan-Putumayo	Tinigua	2*	1 exploration well
Sinú	SN-1	N/A (currently a Technical Evaluation Area)	1 stratigraphic well (pending approval to convert to exploration well)
Sinú	SN-3	1	1 exploration well, including vertical seismic program and biostratigraphy studies

*As of February 22, 2018, suspended due to licensing restrictions

** As of February 22, 2018, suspended due to security issues

Royalties

Colombian royalties are regulated under Colombia Law 756 of 2002, as modified by Law 1530 of 2012. All discoveries made subsequent to the enactment of Law 756 of 2002 have the sliding scale royalty described below. Discoveries made before the

enactment of Law 756 of 2002 have a royalty of 20%, and in the case of such discoveries under association contracts reverted to the national government, an additional 12% applies for a total royalty of 32%.

The ANH contracts to which we are a party all have royalties that are based on a sliding scale described in Law 756 of 2002. This royalty works on an individual oil field basis starting with a base royalty rate of 8% for gross production of less than 5,000 bopd. The royalty increases in a linear fashion from 8% to 20% for gross production between 5,000 and 125,000 bopd and is stable at 20% for gross production between 125,000 and 400,000 bopd. For gross production between 400,000 and 600,000 bopd the rate increases in a linear fashion from 20% to 25%. For gross production in excess of 600,000 bopd the royalty rate is fixed at 25%. In addition to the sliding scale royalty, the following blocks have additional x-factor royalties: Llanos-22, Putumayo-2, Putumayo-4 and Putumayo-7: 1%; Sinu-1 and Llanos-10: 3%; Putumayo-31: 12%; Sinu-3:17%; Llanos-1: 31%; Llanos-53: 33%; Llanos-70: 31%; Putumayo 25: 19%; Santana: 32% and Nancy-Burdine-Maxine: 20% for existing production and sliding scale for new discoveries or incremental production duly approved by ANH.

For gas fields, the royalty is on an individual gas field basis starting with a base royalty rate of 6.4% for gross production of less than 28.5 MMcf of gas per day. The royalty increases in a linear fashion from 6.4% to 20% for gross production between 28.5 MMcf of gas per day and 3.42 Bcf of gas per day and is stable at 16% for gross production between 712.5 to 2,280 MMcf of gas per day. For gross production between 2.28 to 3.42 Bcf of gas per day the rate increases in a linear fashion from 16% to 20%. For gross production in excess of 3.42 Bcf of gas per day the royalty rate is fixed at 20%.

An additional royalty (the “HPR royalty”) applies on exploration and production contracts signed under the ANH oil regulatory regime in 2004 and onwards when cumulative gross production from an Exploitation Area is greater than five MMbbl and reference prices exceed the trigger price defined in the contract. For exploration and production contracts awarded in the 2010, 2012 and 2014 Colombia Bid Rounds, the HPR royalty will apply once the production from the area governed by the contract, rather than any particular Exploitation Area designated under the contract, exceeds five MMbbl of cumulative production. At December 31, 2017, our production from the Costayaco and Moqueta Exploitation Areas in the Chaza block and the Acordionero Exploitation Area in the Midas Block were subject to the HPR royalty. The HPR royalty is calculated based on the established percent (S) of the part of the average monthly reference WTI price (P) that exceeds a base price (Po), divided by the average monthly reference price (P).The Guayuyaco and Suroriente Blocks have the sliding scale royalty but do not have the additional royalty.

In addition to these government royalties, our original interests in the Guayuyaco and Chaza Blocks acquired on our entry into Colombia in 2006 are subject to a third party royalty. The additional interests in Guayuyaco and Chaza that we acquired on the acquisition of Solana in 2008 are not subject to this third party royalty. The overriding royalty rights start with a 2% rate on working interest production less government royalties. For new commercial fields discovered within 10 years of the agreement date and after a prescribed threshold is reached, Crosby Capital, LLC (“Crosby”) reserves the right to convert the overriding royalty rights to a net profit interest (“NPI”). This NPI ranges from 7.5% to 10% of working interest production less sliding scale government royalties, as described above, and operating and overhead costs. No adjustment is made for the HPR royalty. On certain pre-existing fields, Crosby does not have the right to convert its overriding royalty rights to an NPI. In addition, there are conditional overriding royalty rights that apply only to the pre-existing fields. Currently, we are subject to a 10% NPI on 50% of our working interest production from the Costayaco and Moqueta Fields in the Chaza Block and 35% of our working interest production from the Juanambu Field in the Guayuyaco Block, and overriding royalties on our working interest production from the Guayuyaco Field in the Guayuyaco Block.

The Putumayo-7 Block is also subject to a third party royalty in addition to the government royalties. Pursuant to the terms of the agreement by which the interests in the Putumayo-7 Block were acquired, a 10% royalty on production from the Putumayo-7 Block is payable to a third party. The terms of the royalty allow for transportation costs, marketing and handling fees, government royalties (including royalties payable to the ANH pursuant to Section 39 of the contract for the Putumayo-7 Block - the “Rights Due to High Prices”) and taxes (other than taxes measured by the income of any party, and other than VAT or any equivalent) to be paid in cash or kind to the Government of Colombia (or any federal, state, regional or local government agency) and ANH, and a 1% ’X’ factor payment to be deducted from production revenue prior to the royalty being paid to a third party.

Oil and Gas Properties - Brazil and Peru

As noted above, during 2017, we completed the sale of our assets in Brazil and Peru.

Until June 30, 2017, we had a 100% WI in six blocks in Brazil and were the operator in all of these blocks. The Brazilian properties were located in the Recôncavo Basin in Eastern Brazil in the State of Bahia.

Until December 18, 2017, we had a 100% WI in five blocks in Peru and were the operator in all of these blocks. Since that date, we have owned a minority equity interest in Sterling, which owns and operates assets in Peru. Please read “2017 Overview - Acquisitions and Dispositions” above.

Administrative Facilities

Our principal executive offices are located in Calgary, Alberta, Canada. The Calgary office lease will expire on November 29, 2022. We also have office space in Colombia.

Estimated Reserves

Our 2017 reserves were independently prepared by McDaniel International Inc. (“McDaniel”), a wholly owned subsidiary of McDaniel & Associates. McDaniel & Associates was established in 1955 as an independent Canadian consulting firm and has been providing oil and gas reserves evaluation services to the world's petroleum industry for the past 60 years. They have internationally recognized expertise in reserves evaluations, resource assessments, geological studies, and acquisition and disposition advisory services. McDaniel's office is located in Calgary, Canada. The technical person primarily responsible for the preparation of our reserves estimates at McDaniel meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The primary internal technical person in charge of overseeing the preparation of our reserve estimates is the Vice President, Asset Management. He has a B. Eng (Hons) degree in mechanical engineering and is a professional engineer and member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta. He is responsible for our engineering activities including reserves reporting, asset evaluation, reservoir management and field development. He has over 20 years of experience working internationally in the oil and gas industry.

We have developed internal controls for estimating and evaluating reserves. Our internal controls over reserve estimates include: 100% of our reserves are evaluated by an independent reservoir engineering firm, at least annually; and review controls are followed, including an independent internal review of assumptions used in the reserve estimates and presentation of the results of this internal review to our reserves committee. Calculations and data are reviewed at several levels of the organization to ensure consistent and appropriate standards and procedures. Our policies are applied by all staff involved in generating and reporting reserve estimates including geological, engineering and finance personnel.

The process of estimating oil and gas reserves is complex and requires significant judgment, as discussed in Item 1A. “Risk Factors”. The reserve estimation process requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. Therefore, the accuracy of the reserve estimate is dependent on the quality of the data, the accuracy of the assumptions based on the data and the interpretations and judgment related to the data.

Proved reserves are reserves 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 under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Estimates of proved reserves are generated through the integration of relevant geological, engineering, and production data, utilizing technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate. Probable reserves are 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. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us.

Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of possible reserves are also inherently imprecise. Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

The following table sets forth our estimated reserves NAR as of December 31, 2017.



	Oil	Natural Gas	Oil and Natural Gas
Reserves Category	(Mbbl)	(MMcf)	(MBOE)
Proved
Total proved developed reserves	39,487	1,431	39,726
Total proved undeveloped reserves	19,467	653	19,576
Total proved reserves	58,954	2,084	59,302

Probable
Total probable developed reserves	13,499	307	13,550
Total probable undeveloped reserves	41,442	1,311	41,661
Total probable reserves	54,941	1,618	55,211

Possible
Total possible developed reserves	16,893	320	16,946
Total possible undeveloped reserves	40,955	1,312	41,174
Total possible reserves	57,848	1,632	58,120

Product Prices Used In Reserves Estimates

The product prices that were used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market. The average realized prices for reserves in the report are:



Oil and NGLs ($/bbl) - Colombia	$	43.00
Natural Gas ($/Mcf) - Colombia	$	3.67
ICE Brent - average of the first day of each month price for the 12-month period	$	54.19

These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2017. We do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.

Proved Undeveloped Reserves

At December 31, 2017, we had total proved undeveloped reserves NAR of 19.6 MMBOE (December 31, 2016 - 14.9 MMBOE), which were 100% in Colombia (December 31, 2016 – 70%). Approximately 64%, 13% , 10% and 7% of proved undeveloped reserves are located in our Acordionero, Costayaco, Cumplidor and Moqueta Fields, respectively, in Colombia. None of our proved undeveloped reserves at December 31, 2017 have remained undeveloped for five years or more since initial disclosure as proved reserves and we have adopted a development plan which indicates that the proved undeveloped reserves are scheduled to be drilled within five years of initial disclosure as proved reserves.

Material changes in proved undeveloped reserves are summarized in the table below:



	Colombia - Oil Equivalent (MMBOE)		Brazil - Oil Equivalent (MMBOE)		Total - Oil Equivalent (MMBOE)
Balance, December 31, 2016	10.4		4.5		14.9
Converted to proved producing	(5.3	)	—		(5.3	)
Discoveries and extensions	10.4		—		10.4
Improved recovery	2.5		—		2.5
Technical revisions	1.6		—		1.6
Sale	—		(4.5	)	(4.5	)
Balance, December 31, 2017	19.6		—		19.6

In 2017, we converted 5.3 MMBOE, or 51% of 2016 Colombian proved undeveloped reserves, to developed status. In 2017, we made investments, consisting solely of capital expenditures, of $62.8 million in Colombia associated with the development of proved undeveloped reserves.

Production, Revenue and Price History

Certain information concerning production, prices, revenues and operating expenses for the three years ended December 31, 2017 is set forth in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the Unaudited Supplementary Data provided following our Financial Statements in Item 8, which information is incorporated by reference here.

The following table presents oil and NGL production NAR from our Costayaco, Moqueta and Acordionero Fields for the three years ended December 31, 2017:



	Year Ended December 31,
	2017						2016						2015
	Costayaco		Moqueta		Acordionero		Costayaco		Moqueta		Acordionero		Costayaco		Moqueta
Oil and NGL's, bbl	3,173,659		1,550,344		3,131,577		3,975,842		2,091,361		648,518		4,053,977		2,005,444
Average sales price of oil and NGL's per bbl	$	43.55	$	45.05	$	43.90	$	33.52	$	32.86	$	35.87	$	42.57	$	42.10
Operating expenses of oil and NGL's per bbl	$	11.70	$	15.27	$	10.34	$	13.71	$	10.50	$	8.00	$	14.87	$	15.93

We prepared the estimate of standardized measure of proved reserves in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification 932, “Extractive Activities – Oil and Gas”.

Drilling Activities

The following table summarizes the results of our exploration and development drilling activity for the past three years. Wells labeled as “In Progress” for a year were in progress as of December 31, 2017, 2016 or 2015. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to Gran Tierra of productive wells compared to the costs of dry holes.



	2017		2016		2015
	Gross	Net	Gross	Net	Gross	Net
Colombia
Exploration
Productive	2.00	1.55	2.00	2.00	—	—
Dry	—	—	—	—	1.00	1.00
In Progress	2.00	2.00	1.00	1.00	—	—
Development
Productive	17.00	13.63	7.00	7.00	7.00	5.16
Service	2.00	2.00	2.00	2.00	—	—
Dry	—	—	1.00	1.00	—	—
In Progress	2.00	1.70	3.00	3.00	6.00	6.00
Total Colombia	25.00	20.88	16.00	16.00	14.00	12.16

Peru
Development
Service	—	—	—	—	1.00	1.00
Dry	—	—	—	—	1.00	1.00
Total Peru	—	—	—	—	2.00	2.00

Total	25.00	20.88	16.00	16.00	16.00	14.16

Of the four wells in progress in Colombia as at December 31, 2016, all continued to be in progress at December 31, 2017.

In 2017, we also continued pressure maintenance projects in the Costayaco and Moqueta Fields in Colombia.

Well Statistics

The following table sets forth our productive wells as of December 31, 2017:



	Oil Wells		Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Colombia⁽¹⁾	120.0	87.9	—	—	120.0	87.9
	120.0	87.9	—	—	120.0	87.9

⁽¹⁾ Includes 17.0 gross and 13.8 net water injector wells and 67.0 gross and 62.3 net wells with multiple completions.

Developed and Undeveloped Acreage

At December 31, 2017, our acreage was located 100% in Colombia. The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2017:

Developed

Undeveloped

Total

Gross

Net

Gross

Net

Gross

Net

Colombia⁽¹⁾

261,668

137,092

2,684,400

1,936,620

2,946,068

2,073,712

⁽¹⁾Excludes our interest in 2 blocks in Colombia with a total of 0.1 million net acres for which government approval of relinquishments or sale was pending at December 31, 2017.

Research and Development

We utilize existing technology, industry best practices and continual process improvement to execute our business plan. We have not expended any resources on pursuing research and development initiatives.

Marketing and Major Customers

Colombia

Our oil reserves and production in Colombia are mainly located in the Middle Magdalena Valley (“MMV”) and Putumayo Basin. In MMV, our focus is on the Acordionero Field, where production is approximately 19° API and represented 33% of our production in 2017. The Putumayo production (as defined below) is approximately 29° API and represented 59% of our production in 2017.

We have entered into numerous agreements to sell oil produced in the Chaza and Guayuyaco Blocks (the “Putumayo production”). These agreements are subject to renegotiation for terms between three to twelve months and generally contain mutual termination provisions with 30 days' notice. The volume of crude oil does not include the volume of oil corresponding to royalties taken in kind, but does include volumes relating to HPR royalties.

We may, but are not obligated to, sell up to 100% of our Putumayo production to Ecopetrol. The Ecopetrol agreement will expire March 31, 2018. We deliver our oil to Ecopetrol through our transportation facilities which include pipelines, gathering systems and through the transportation and logistics assets of CENIT Transporte y Logistica de Hidrocarburos S.A.S (“CENIT”), a wholly-owned subsidiary of Ecopetrol. The point of sale of our Putumayo production to Ecopetrol is the Port of Tumaco on the Pacific coast of Colombia or at the Ecuador border, in the event of pipeline disruptions.

We have entered into ship and pay transportation agreements (the “Transportation Agreements”) with CENIT. These agreements will expire November 30, 2018. Pursuant to the Transportation Agreements we pay a transportation tariff and transportation tax for the transportation of the Putumayo production from the Putumayo Basin to the Port of Tumaco. Pursuant to the Transportation Agreements, Gran Tierra Energy Colombia Ltd. has the right to transport up to 10,000 bopd, subject to availability of capacity, (1) from Santana Station to CENIT’s facility at Orito through CENIT’s Mansoya – Orito Pipeline (“OMO”), and (2) from CENIT’s facility at Orito to the Port of Tumaco through CENIT’s Orito – Tumaco Pipeline (“OTA”). Generally, under these agreements, CENIT is liable (subject to specified limitations) for pollution clean up costs resulting from incidents during transportation. The cost of oil lost during transportation is shared by the parties that ship oil on the pipeline, in proportion to their share of total volumes shipped.

In addition to the ship and pay transportation agreements described above, we have Firm Capacity Transportation Agreements for 6,000 bopd, of which 3,000 bopd are under ship or pay agreements and 3,000 bopd are under ship and pay agreements. These agreements will expire October 31, 2020.

Putumayo production is also sold to multiple other parties, in addition to Ecopetrol. Other sales in Putumayo are generally delivered at the wellhead. Oil is delivered and sold at the Costayaco battery and Santana station and loaded into trucks. When oil is loaded into trucks there are multiple evacuation routes. When oil is delivered to facilities at Babillas Station, the sales point is the Port of Coveñas and it is sold as Vasconia 24 API. For oil delivered via truck to Amazonas, Oleoducto de Crudos Pesados (OCP) Ecuador S.A. Ecuador, the sales point is the Port of Esmeraldas and it is sold as Chaza blend 27.9 API. For oil delivered via pipeline to the Port of Esmeraldas, Ecuador, it is sold as NAPO 18 API.

Trucking options for Putumayo include: (1) from Santana Station to Ecopetrol’s storage terminal at Orito, a distance of approximately 47 kilometers; (2) from Santana Station to OCP’s Amazonas Station truck offloading facility, a distance of approximately 128 kilometers; (3) from the Costayaco Field to Hocol’s storage terminal at Babillas, approximately 363 kilometers north of the Chaza Block; and (4) from the Costayaco Field to Puerto Bahia, Cartagena approximately 1,589 kilometers.

In MMV, the Acordionero Field has a firm volumetric contract which will end by approximately the first quarter of 2018. A tender process is ongoing and will award in time for completion of present contract. Presently, we truck these volume 530 kilometers to the buyer at Puerto Bahia, Cartagena Bay. We are evaluating the construction of a pipeline tie in at the Acordionero Field, which is expected to provide us with access to the Port of Coveñas for future sales at the export terminal. Production from the minor fields in MMV is sold at the wellhead on a short-term contract which will expire February 28, 2018. A tender process is ongoing.

Trucking options for Llanos include: (1) from the Garibay Jilguero Field to facilities at Cusiana Station, a distance of approximately 75 kilometers; and (2) from the Llanos 22 Ramiriqui Field to facilities at Cusiana Station, a distance of approximately 35 kilometers.

We receive revenues for our Colombian oil sales in U.S. dollars. Oil prices for sales of our crude oil are defined by agreements with the purchasers of the oil and are based generally on an average price for crude oil, using ICE Brent, with adjustments for differences in quality, specified fees, transportation fees and transportation tax. Pipeline tariffs are denominated in U.S. dollars and trucking costs are in Colombian Pesos.

Competition

The oil and gas industry is highly competitive. We face competition from both local and international companies. This competition impacts our ability to acquire properties, contract for drilling and other oil field equipment and secure trained personnel. Many competitors, such as Ecopetrol, Colombia's national oil company, have greater financial and technical resources. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. 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. There is substantial competition for land contracts, prospects and resources in the oil and natural gas industry, and we compete to develop and produce those reserves cost effectively. In addition, we compete to monetize our oil production: for transportation capacity and infrastructure for the delivery of our products, to maintain a skilled workforce and to obtain quality services and materials.

Geographic Information

We have one reportable segment based on geographic organization, Colombia. Prior to the sale of our Brazil business unit effective June 30, 2017 and our Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. Information regarding our geographic segment, including information on revenues, assets, expenses and net income, can be found in Note 3 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 Colombia, 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 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 Administration

We operate in Colombia through Colombian branches of the following entities: Gran Tierra Energy Colombia Ltd., Gran Tierra Colombia Inc. and Petrolifera Petroleum (Colombia) Limited. Gran Tierra Energy Colombia Ltd. and Gran Tierra Colombia Inc. are currently qualified as operators of oil and gas properties by the ANH.

In Colombia, the ANH is 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. Since 2003, Ecopetrol, the Colombian national oil company, has been a public company owned in majority by the state with the main purpose of exploring and producing hydrocarbons similar to any other oil company. In addition, Ecopetrol is a major purchaser and marketer of oil in Colombia and operates the majority of the oil transportation infrastructure in the country.

The ANH uses an exploration risk contract, or the Exploration and Production Contract, which provides full risk/reward benefits for the contractor. Under the terms of this 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 contains a number of exploration periods and each period has

an associated work commitment. The production phase lasts a number of years (usually 24) from the declaration of a commercial hydrocarbon discovery.

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). 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.

Environmental Compliance

Our activities are subject to 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 regional and federal authorities in Colombia. Such regulations relate to environmental impact studies, the discharge of pollutants into air and water, water use and management, the management of non-hazardous and 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 as well as cultural resources and areas inhabited by indigenous peoples, among others. Risks are inherent in oil and gas exploration, development and production operations. These risks include blowouts, fires, or spills. Significant costs and liabilities may be incurred in connection with environmental compliance issues. Licenses and permits 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 have an adverse effect on our operations. Spills and releases into the environment of petroleum products can result in remediation costs and liability for damages. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. Moreover, violations of environmental laws and regulations can result in the 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 could adversely affect our operations. Governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. We do not expect that the cost of compliance with regional and federal provisions, which have been enacted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment or natural resources, will be material to us.

We have implemented a company wide web-based reporting system which allows us to track incidents and respective corrective actions and associated costs. We have a Corporate Health, Safety, and Environmental Management System as well as a Corporate Environmental Management Plan (EMP). The EMP is based on the environmental performance standards of the World Bank/IFC and reflects best industry practices. We have 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, reporting to executive management as well as a committee of the Board. We have a schedule of internal audits and routine checking of practices and procedures and conduct emergency response exercises.

Employees

At December 31, 2017, we had 324 full-time employees (December 31, 2016 - 387): 81 located in the Calgary corporate office, and 243 in Colombia (171 staff in Bogota and 72 field personnel). During 2017, we completed the sale of our assets in Brazil and Peru. None of our employees are represented by labor unions, and we consider our employee relations to be good.

Available Information

We make available free of charge through our website at www.grantierra.com our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed or furnished with the Securities and Exchange Commission (“SEC”). Our website address is provided solely for informational purposes. Information on our website is not incorporated into this Annual Report or otherwise made part of this Annual Report. We intend to use our website as a means for distributing information to the public for purposes of compliance with Regulation FD.

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 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.

Item 1A. Risk Factors

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce our profitability, growth and value.

Substantially all of our revenues are derived from the sale of oil, which price is based on world demand, supply, weather, pipeline capacity constraints, inventory storage levels and other factors, geopolitical unrest, all of which are beyond our control. Historically, the market for oil has been volatile, and the market is likely to continue to be volatile in the future. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contracts 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 or sustained low prices may have a material adverse effect on our financial condition, the future results of our operations (including rendering existing projects unprofitable), financing available to us, and quantities of reserves recoverable on an economic basis, as well as the market price for our securities.

Estimates of oil and natural gas reserves may be inaccurate and our actual revenues may be lower than estimated.

We make estimates of oil and natural gas reserves, upon which we base our financial projections and capital expenditure plans. 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. Economic factors beyond our control, such as world oil prices, interest rates, inflation, and exchange rates, will also impact the quantity and value of our reserves.

The process of estimating oil and gas reserves is complex, and requires 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 reserves estimates are inherently imprecise. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. 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. 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.

Actual future production, oil and natural gas prices, revenues, taxes, exploration and development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those we estimate. such changes could require us to materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Unless we are able to replace our reserves and production, and develop and manage oil and gas reserves and production on an economically viable basis, our financial condition and results of operations will be adversely impacted.

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.

Exploration, development and production costs (including transportation and workover costs), marketing costs (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 variations 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.

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.

Exploration for oil and natural gas, and development of new formations, is risky.

Oil and natural gas exploration involves a high degree of operational and financial risk. These risks are more acute in the early stages of exploration, appraisal and development. It is difficult to predict the results and 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.

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.

Our business requires significant capital expenditures, and we may not have the resources necessary to fund these expenditures.

Our capital program for 2018 is $265 to $285 million for exploration and development. This does not include the cost of any acquisitions. We expect to finance our 2018 capital program primarily through cash flows from operations. Funding this program from cash flow from operations relies in part on oil prices being greater than $50 per barrel, or higher.

If cash flows from operations, cash on hand (including proceeds of the offering of senior unsecured notes completed in February 2018) and available capacity under our credit facility are not sufficient to fund our capital program, we may be required to seek external financing or to delay or reduce our exploration and development activities, which could impact production and reserve growth.

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 pledge of assets, involve covenants that would restrict our business activities, 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 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 would adversely impact our financial results.

Our ability to obtain needed financing may be impaired by factors such as weak 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, low or declining prices of oil and natural gas on the commodities markets, and the loss of key management. Further, if oil 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. 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.

The borrowing base under our revolving credit facility may be reduced by the lenders, which could prevent us from meeting our future capital needs.

The borrowing base under our revolving credit facility is currently $300 million. Our borrowing base is redetermined by the lenders twice per year, and will be re-determined no later than May 2018. Our borrowing base may decrease as a result of a 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, we could be required to repay any indebtedness in excess of the redetermined borrowing base, which could deplete cash flow from operations or require additional financing. Further, our borrowing base is made available to us subject to the terms and covenants of our revolving credit facility, including compliance with the ratios and other financial covenants of such facility, and a failure to comply with such ratios or covenants could force us to repay a portion of our borrowings and suffer adverse financial impacts.

Our business is subject to local legal, social, political and economic factors that are beyond our control, which could impair or delay our ability to expand our operations or operate profitably.

We operate our business in Colombia, where all of our reserves and production are currently located, and may eventually expand to other countries. Exploration and production operations are subject to legal, social, political and economic uncertainties, including terrorism, military repression, social unrest and activism, strikes by local or national labor groups, interference with private contract rights , 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. When such disruptions occur, they may adversely impact our operations and threaten the economic viability of our projects or our ability to meet our production targets.

Colombia has experienced and may in the future experience 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 but not limited to: the imposition of additional taxes; nationalization; changes in energy or environmental policies or the personnel administering them; changes in oil and natural gas pricing policies; and royalty changes or increases. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets or renegotiation or nullification of existing concessions and contracts. There will be national elections in Colombia in 2018, resulting in a new country president who may take positions on oil and gas issues that are contrary to our interests. Any changes in the ruling government, oil and gas or investment regulations and policies or a shift in political attitudes in countries in which we operate are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.

We are vulnerable to risks associated with geographically concentrated operations.

The vast majority of our production comes from three fields. For the year ended December 31, 2017, the Acordionero, Costayaco and Moqueta Fields collectively generated 82% of our production and at December 31, 2017, these three fields accounted for 81% of our proved reserves. As a result of this concentration, we may be disproportionately exposed to the impact of, among other things, regional supply and demand factors including limitations on our ability to most profitably sell or market our oil and gas to a smaller pool of potential buyers, delays or interruptions of production from wells in these areas caused by governmental regulation, community protests, guerrilla activities, processing or transportation capacity constraints, continued authorization by the government to explore and drill in these areas, severe weather events and the availability of drilling rigs and related equipment, facilities, personnel or services. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

We rely on local infrastructure and the availability of transportation for storage and shipment of our products. This infrastructure, including storage and transportation facilities, is less developed than that in North America and may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. Further, we operate in remote areas and may rely on helicopters, 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 affect our ability to add to our reserve base or produce oil, or 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.

Social disruptions or community disputes in our areas of operations may delay production and result in lost revenue.

To enjoy the support and trust of local populations and governments, we must demonstrate a commitment to: providing local employment, training and business opportunities; a high level of environmental performance; open and transparent communication; and 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 community and the area. Improper management of these relationships could lead to a delay or suspension in operations, loss of license or major impact to our reputation in these communities, which could adversely affect our business. For example, in 2017, we postponed the exploration drilling program at Prosperidad-1 in the Llanos basin due to road blockades and civil disruption along the route to the well site. We cannot ensure that similar disruptions will not be experienced in future and we cannot predict their potential impacts, which may include delays or loss of production, standby charges, stranded equipment, or damage to our facilities. In addition, we must comply with legislative requirements for prior consultation of communities and ethnic groups who are

affected by our proposed projects in Colombia. Notwithstanding our compliance with these requirements, we may be sued by such communities through a writ for protection or tutela in the Colombian courts for enhanced consultation, potentially leading to increased costs, operational delays and other impacts. In addition, several areas in Colombia have conducted Popular Consultations, essentially referendums, on extractive industries. The referendums were organized by opponents of the mining or oil and gas industries. To this point all have passed with a large majority voting to prohibit extractive industry activity in the particular region, but it remains unclear to what extent such results are legally binding and take precedence over the issuance of mineral rights by the national government. While we believe we have minimal exposure to Popular Consultations at this point, it appears that some groups are seeking to pose a referendum question in the Yopal/Casanare area, potentially affecting our ability to drill our El Porton exploration prospect. It is not yet clear if they will succeed in gaining the requisite number of signatures to conduct the referendum or whether all of the other legal and procedural requirements will be satisfied by the proponents.

We are dependent on obtaining and maintaining permits and licenses from various governmental authorities

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous licenses, permits, approvals and certificates, including environmental and other operating permits. We may not be able to obtain, sustain or renew such licenses and permits on a timely basis or at all. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop and explore on our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. 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. There can be no assurance that future political conditions in Colombia will not result in changes to policies with respect to foreign development and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities.

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.

Guerilla activity and security concerns in Colombia may disrupt our operations.

For over 50 years, the Colombian government was engaged in a conflict with two main Marxist guerrilla groups: the Revolutionary Armed Forces of Colombia ("FARC") and the National Liberation Army ("ELN"). Oil pipelines have been primary targets of guerrilla activity. On September 26, 2016, the Colombian government and the FARC signed a peace agreement (the "Peace Agreement") and, on November 30, 2016, the Peace Agreement was ratified by Colombia's government, the result of which was the demobilization and disarmament of the FARC. A ceasefire negotiated between the ELN and the Colombian government recently ended and it is not currently known whether or to what degree violence will result and whether and to what degree that violence may impact our operations. Notwithstanding the Peace Agreement and the continuing attempts by the Colombian government to reduce or prevent activity of guerrilla dissidents, such efforts may not be successful and such activity may continue to disrupt our operations in the future or cause us higher security costs and could adversely impact our financial condition, results of operations or cash flows.

Colombia also has a history of security problems. Our efforts to ensure the security of our physical assets 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 our Bogota head office personnel or operations in Colombia or that this violence will not adversely affect our operations in the future and cause significant loss. If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected.

Environmental regulation and risks may adversely affect our business.

Environmental regulation is stringent and costs and expenses of regulatory compliance are increasing. All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to an extensive suite of international conventions and national and regional 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. Failure to comply with these laws and regulations may result in the suspension or termination of

operations and subject us to administrative, civil and criminal fines and penalties. Our operations create the risk of significant environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water or for certain other environmental impacts. There is uncertainty around the impact of environmental laws and regulations, including those presently in force and those expected to be proposed in the future. We cannot predict how future environmental laws will be interpreted, administered or enforced, but more stringent laws or regulations or more vigorous enforcement policies could in the future require material expenditures by us for the installation and operation of compliant systems; therefore it is impossible at this time to predict the nature and impact of those requirements on our company however they may have a material adverse impact on our business.

Given the nature of our business, there are inherent risks of oil spills at drilling or operations sites due to operational failure, accidents, sabotage, pipeline failure or tampering or escape of oil due to the transportation of the oil by truck. All of these may lead to significant potential environmental liabilities, such as damages, litigation costs, clean-up costs or penalties, some of which may be material and for which our insurance coverage maybe inadequate or unavailable.

Most of our revenue is generated outside of Canada and the United States, and if we determine to, or are required to, repatriate earnings from foreign jurisdictions, we could be subject to taxes.

Most of our revenue is generated outside of Canada and the United States. The cash generated from operations abroad is generally not available to fund domestic or head office operations unless funds are repatriated. At this time, we do not intend to repatriate further funds, other than to pay head office charges, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable. On December 22, 2017, the budget reconciliation statute commonly referred to as

the Tax Cuts and Jobs Act (the “Tax Act”) significantly revised U.S. federal corporate income tax law, including the creation of a one-time “transition tax” on a deemed dividend of untaxed accumulated earnings and profits of certain non-U.S. corporations. This deemed dividend does not result in the actual movement of foreign earnings and has no local impact in those non-US jurisdictions. While our analysis of the Tax Act’s impact on our cash tax liability and financial condition has not identified any overall material adverse effect, we are still evaluating the effects of the Tax Act on us and there are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions in the Tax Act. In the absence of guidance on these issues, we will use what we believe are reasonable interpretations and assumptions in applying the Tax Act for purposes of determining our cash tax liabilities and results of operations, which may change as we receive additional clarification and implementation guidance. It is possible that the Internal Revenue Service could issue subsequent guidance or take positions on audit that differ from the interpretations and assumptions that we previously made, which could have a material adverse effect on our cash tax liabilities, results of operations and financial condition.

Foreign currency exchange rate volatility may affect our financial results.

We sell our oil and natural gas production under agreements that are denominated mainly in U.S. dollars. Many of the operational and other expenses we incur, including current and deferred tax liabilities in Colombia, are denominated in Colombian pesos. Most of our administration costs in Canada are incurred in Canadian dollars. As a result, we are exposed to translation risk when local currency financial statements are translated to U.S. dollars, our functional currency. An appreciation of local currencies can increase our costs and negatively impact our results from operations. Because our Consolidated Financial Statements are presented in US$, we must translate revenues, expenses and income, as well as assets and liabilities, into US$ at exchange rates in effect during or at the end of each reporting period. We are also exposed to transaction risk on settlement of payables and receivables denominated in foreign currency.

We may be exposed to liabilities under anti-bribery laws and a finding that we violated these laws could have a material adverse effect on our business.

We are subject to anti-bribery laws in the United States, Canada and Colombia and will be subject to similar laws in other jurisdictions where we may operate in the future. 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 partners of ours or our subsidiaries or affiliates, given that these parties are not always subject to our control or direction. It is our policy to prohibit these practices. However, our existing safeguards and any future improvements to those measures 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. 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) as well as reputational damage and could have a material adverse effect on our business and financial condition.

If the United States imposes sanctions on Colombia in the future, our business may be adversely affected.

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 counter-narcotic agreements may result in the imposition of economic and trade sanctions on Colombia which could result in adverse economic consequences in Colombia including potentially threatening our ability to obtain necessary financing to develop our Colombian properties, and could further heighten the political and economic risks associated with our operations there.

The threat and impact of cyberattacks may adversely impact our operations and could result in information theft, data corruption, operational disruption, and/or financial loss.

We use digital technologies and software programs to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, as well as to process and record financial and operating data. We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexities of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, and global competition for oil and gas resources make certain information attractive to thieves. 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 and therefore it is critical to our business that our facilities and infrastructure remain secure. While we have implemented strategies to mitigate impacts from these types of events, we cannot guarantee that 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. Moreover, if any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.

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 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.

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. Colombia has enacted legislation related to GHG emissions and 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. In addition, Colombia has established the National Energy Efficiency Program, which calls for electric utilities, oil and gas companies, and other energy service companies to develop Energy Efficiency Plans to meet goals set forth by the Ministry and the Mining and Energy Planning Unit.

GHG emissions legislation is emerging and is subject to change. For example, on an international level, in December 2015, almost 200 nations agreed to an international climate change agreement in Paris, France (the “Paris Agreement”), 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. Colombia has signed the Paris Agreement. 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 amount 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. In addition, significant restrictions on GHG emissions could result in decreased demand for the oil that we produce, with a resulting decrease in the value of our reserves. 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. Finally, although we strive to operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

We hold a minority equity investment in Sterling, and our inability, or limited ability, to control the operations or management of Sterling may result in our receiving or retaining less than the amount of benefit we expect.

We hold a minority equity investment in Sterling and our chief executive officer and chief financial officer serve on the board of directors of Sterling. Even though we are able to exercise influence as a minority equity investor in Sterling, our influence of Sterling is limited to our rights under the share purchase agreement and its annexes and Sterling’s charter and bylaws. Such limitations include a covenant by us not to exercise any voting rights associated with our shares in Sterling which exceed 30% of the issued and outstanding common shares of Sterling. As a result, we may be unable to implement or influence Sterling’s business plan, assure quality control, or set the timing and pace of development. Our inability, or limited ability, to control the operations or management of Sterling may result in our receiving or retaining less than the amount of benefit we might otherwise expect to receive from such investment. We may also be unable, or limited in our ability, to cause Sterling to effect significant transactions such as large expenditures or contractual commitments, the development of properties, the construction or acquisition of assets or the borrowing of money. Service on the board of directors by our two senior executive officers will require time commitment and could expose them to liability in such role. If Sterling or its board of directors were to experience events that exposed them to liability or reputational harm, it could have an adverse effect on us or our senior executives, including a decline in the market price of our equity securities.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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 $50.8 million as at December 31, 2017. 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.

Executive Officers of the Registrant

Set forth below is information regarding our executive officers as of February 22, 2018.



Name	Age	Position
Gary S. Guidry	62	President and Chief Executive Officer, Director
Ryan Ellson	42	Chief Financial Officer
Ed Caldwell	68	Vice President, Health, Safety and Environment & Corporate Social Responsibility
Adrian Coral	44	President, Gran Tierra Energy Colombia
James Evans	52	Vice President, Corporate Services
Alan Johnson	46	Vice President, Asset Management
Glen Mah	61	Vice President, Business Development
Susan Mawdsley	51	Vice President, Finance and Corporate Controller
Rodger Trimble	56	Vice President, Investor Relations
Lawrence West	61	Vice President, Exploration

•

Gary Guidry, Chief Executive 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 Onza Energy Inc. from January 2014, until May 2015. From July 2011 to July 2014, Mr. Guidry served as President and Chief Executive Officer of Caracal Energy Inc. Mr. 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 on the Board of Zodiac Exploration Corp., and from October 2009 to March 2014, he served on the board of TransGlobe Energy Corp. Prior to these positions, Mr. Guidry served as Senior Vice President and subsequently President of Alberta Energy Company International, and President and General Manager of Canadian Occidental Petroleum’s Nigerian operations. Mr. Guidry has directed exploration and production operations in Yemen, Syria and Egypt and 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 17 years of experience in a broad range of international corporate finance and 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 Chad, Africa from August 2011 until July 2014. Prior to Caracal, Mr. Ellson was 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 reserve based lending facility and was 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 Chartered Accountant and holds a Bachelor of Commerce and a Master of Professional Accounting from the University of Saskatchewan.

•

Ed Caldwell, Vice President, Health, Safety and Environment & Corporate Social Responsibility. Mr. Caldwell has been Gran Tierra's Vice President, Health, Safety and Environment & Corporate Social Responsibility, since June 2016. Mr. Caldwell had a distinguished 27-year career with ExxonMobil and Imperial Oil, and most recently worked with Caracal Energy Inc. in Caracal's efforts and achievement in Chad. Mr. Caldwell has extensive experience in senior Regulatory Approvals and HSE Management roles in Canada, Asia, Russia, and Africa. He has also worked with the Government of Canada and, in that capacity, represented Canada at the OECD Energy/Environment Committee as well as at the Intergovernmental Panel on Climate Change. Mr. Caldwell graduated in Chemical Engineering (Distinction) from Dalhousie University.


•	Adrian Coral, President, Gran Tierra Energy Colombia. Mr. Coral joined Gran Tierra in August 2006 as an operations 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 22 years of experience as an engineer or manager in the oil and gas industry. Mr. Coral graduated from the Universidad de América – Bogotá D.C. with a degree as a Petroleum Engineer and from the School of Business Management – Bogotá D.C with degree in Project Management.

•

James Evans, Vice President, Corporate Services. Mr. Evans has been Gran Tierra's Vice President, Corporate Services, since May 2015. Mr. Evans has over 28 years of experience including working the last 12 years in the international oil and gas industry. Most recently, Mr. Evans was the Head of Compliance & Corporate Services for Glencore E&P (Canada) from July 2014 to December 2014, and prior thereto Vice President of Compliance & Corporate Services at Caracal Energy from July 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. 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 Calgary.

•

Alan Johnson, Vice President, Asset Management. Mr. Johnson has been Gran Tierra's Vice President, Asset Management, since May 2015. Mr. Johnson is a professional engineer with more than 20 years of experience 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. 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 with a 1st Class B. Eng (Hons) from Heriot Watt University in Scotland. Mr. Johnson is a Chartered Engineer in the UK and a Professional Engineer in Alberta.

•

Glen Mah, Vice President, Business Development. Mr. Mah has been Gran Tierra's Vice President, Business Development since June 2016. He is a Petroleum Geologist with extensive management experience covering the execution of exploration programs, field development and asset management for conventional and unconventional hydrocarbons. He has worked with onshore and offshore projects in various petroleum basins in the Americas, Africa, Middle East and Asia. Mr. Mah was the Chief Geologist with the highly successful Tanganyika Oil Company Ltd. Mr. Mah has Alberta-registered Professional designation with APEGA and holds a Bachelor of Science degree Specialization in Geology from the University of Alberta.

•

Susan Mawdsley, Vice President, Finance and Corporate Controller. Ms. Mawdsley has been Gran Tierra's Vice President, Finance, since June 2016, and has been Gran Tierra's Corporate Controller since 2012. She is a Chartered Accountant with 25 years of experience in the oil and gas industry. She has direct responsibility for the finance departments in all business units, as well as internal audit. Prior to joining Gran Tierra in 2011, she was an independent consultant providing contract controller, CFO, and other finance related services to publicly traded domestic and international oil and gas companies. Ms. Mawdsley is a Chartered Accountant and holds a Bachelor of Music in Performance degree from the University of Toronto.

•

Rodger Trimble, Vice President, Investor Relations. Mr. Trimble has been Gran Tierra's Vice President, Investor Relations since June 2016. He is a Professional Engineer with more than 30 years of experience in domestic and international basins in various management positions. Prior to joining Gran Tierra, Mr. Trimble was Head of Corporate Planning, Budgeting & Finance with Glencore E&P Canada Inc. and prior thereto Director Corporate Planning, Budget & Business Development with Caracal Energy Inc. (acquired by Glencore E&P). He has held several senior management positions ranging from Country Manager in Argentina with Canadian Hunter Exploration, Vice President, Exploitation with Esprit Energy Trust, Manager, Reservoir Engineering with Apache Canada Inc. and Manager, Upstream Evaluations - Frontiers & International with Husky Energy. Mr. Trimble is an Alberta-registered

Professional Engineer and a member of APEGA. He received a Bachelor of Science in Petroleum Engineering (with Distinction) from Stanford University.

•

Lawrence West. Vice President, Exploration. Mr. West has 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 interior rift basins within Chad and led a successful exploration program. During his tenure he successfully executed two large 2D/3D seismic shoots in 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 on the team that merged with Conwest. He built and led the AEC East team to the Rocky Mountain USA basins. His career began with Imperial Oil working on prospect and reservoir characterization, in multi-disciplinary teams, and as a technical mentor to exploration teams. Lawrence has an Honours Bachelor of Science in Geology from McMaster University and an MBA, specializing in economics, from the University of 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 American 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 22, 2018, there were approximately: 37 holders of record of shares of our Common Stock and 385,394,642 shares outstanding with $0.001 par value; and one share of Special A Voting Stock, $0.001 par value representing approximately one holder of record of 1,688,889 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 15 holders of record of 4,219,176 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, 2016, through the end of the fourth quarter of 2017, the following table shows the high and low closing sale prices per share of our Common Stock as reported on the NYSE American.



	High		Low
Fourth Quarter 2017	$	2.76	$	2.02
Third Quarter 2017	$	2.38	$	1.96
Second Quarter 2017	$	2.81	$	2.01
First Quarter 2017	$	3.05	$	2.44
Fourth Quarter 2016	$	3.23	$	2.60
Third Quarter 2016	$	3.14	$	2.65
Second Quarter 2016	$	3.48	$	2.31
First Quarter 2016	$	2.84	$	1.87

Dividend Policy

We have never declared or paid dividends on the shares of Common Stock and we intend to retain future earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future. Payment of future dividends, if any, would be at the discretion of our Board of Directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs. Under the terms of the credit facility, the Company cannot pay any dividends to its shareholders if it is in default under the facility and, if the Company is not in default, it is required to obtain bank approval for dividend payments to shareholders outside of the credit facility group which comprises the Company’s subsidiaries in Colombia, Canada and the United States of America (the “Credit Facility Group”).

Issuer Purchases of Equity Securities



	(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⁾
May 1-31, 2017	1,138,246	2.44	1,138,246	18,402,113
June 1-30, 2017	3,097,644	2.33	3,097,644	15,304,469
December 1-31, 2017	3,468,487	2.28	3,468,487	11,835,982
	7,704,377	2.33	7,704,377	11,835,982

⁽¹⁾ Based on settlement date.

⁽²⁾Exclusive of commissions paid to the broker to repurchase the Common Stock.

⁽³⁾ On January 30, 2017, we announced that we intended to implement a share repurchase program or normal course issuer bid (the “2017 Program”) through the facilities of the TSX, the NYSE American and eligible alternative trading platforms in Canada and the United States. We received regulatory approval from the TSX to commence the 2017 Program on February 6, 2017. We were able to purchase at prevailing market prices up to 19,540,359 shares of Common Stock, representing approximately 5.00% of our issued and outstanding shares of Common Stock as of January 27, 2017. The average daily trading volume of shares of Common Stock over the six calendar month period prior to January 24, 2017 was 1,214,973, meaning that we were entitled to purchase, on any trading day, up to 303,743 shares of Common Stock. Shares of Common Stock purchased pursuant to the 2017 Program will be canceled. The 2017 Program expired on February 7, 2018. The 2017 Program could have been terminated by us at any time, subject to compliance with regulatory requirements. Shareholders may obtain a copy of the Notice of Intention to Make A Normal Course Issuer Bid filed with the TSX detailing the 2017 Program free of charge by writing or telephoning us at the address or phone number on the cover page of this Annual Report on Form 10-K.

Performance Graph

The information in this Annual Report on Form 10-K appearing under the heading “Performance Graph” is being “furnished” pursuant to Item 201(e) of Regulation S-K under the Securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act except to the extent that we specifically incorporate it by reference into such filing.

The performance graph below shows the cumulative total shareholder return on our shares for the period starting on December 31, 2012, and ending on December 31, 2017, which was the end of fiscal 2017. This is compared with the cumulative total returns over the same period of the S&P 500 Total Return Index and the S&P O&G E&P Select Index Total Return. The graph assumes that, on December 31, 2012, $100 was invested in our shares and $100 was invested in each of the other two indices, with dividends reinvested on the ex-dividend date without payment of any commissions. The performance shown in the graph represents past performance and should not be considered an indication of future performance.

Item 6. Selected Financial Data

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



Statement of Operations Data
	Year Ended December 31,
	2017			2016			2015			2014			2013
Oil and natural gas sales	$	421,734		$	289,269		276,011			$	559,398		$	646,955

Expenses
Operating	109,869			86,925			75,565			89,753			91,223
Transportation	25,107			31,776			40,204			24,196			18,949
Depletion, depreciation and accretion	131,335			139,535			176,386			185,877			200,851
Asset impairment	1,514			616,649			323,918			265,126			2,000
G&A	39,014			33,218			32,353			51,249			41,115
Severance	1,287			1,319			8,990			—			—
Transaction	—			7,325			—			—			—
Equity tax	1,224			3,098			3,769			—			—
Foreign exchange loss (gain)	2,067			(1,469		)	(17,242		)	(39,535		)	(18,693		)
Financial instruments loss	15,929			10,279			2,027			4,722			—
Other loss	—			—			—			—			4,400
Other gain	—			—			(502		)	(2,000		)	—
Interest expense	13,882			14,145			—			—			—
	341,228			942,800			645,468			579,388			339,845

(Loss) on sale of business units and gain on acquisition	(44,385		)	929			—			—			—
Interest income	1,209			2,368			1,369			2,856			2,174
Income (loss) from continuing operations before income taxes	37,330			(650,234		)	(368,088		)	(17,134		)	309,284

Current income tax expense	24,322			20,122			15,383			92,865			157,126
Deferred income tax expense (recovery)	44,716			(204,791		)	(115,442		)	34,350			(28,865		)
	69,038			(184,669		)	(100,059		)	127,215			128,261

(Loss) income from continuing operations	(31,708		)	(465,565		)	(268,029		)	(144,349		)	181,023
Loss from discontinued operations, net of income taxes	—			—			—			(26,990		)	(54,735		)
Net income (loss)	$	(31,708	)	$	(465,565	)	(268,029		)	$	(171,339	)	$	126,288

(Loss) Income per Share
Basic
(Loss) income from continuing operations	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.51	)	$	0.64
Loss from discontinued operations, net of income taxes	—			—			—			(0.09		)	(0.19		)
Net income (loss)	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.60	)	$	0.45



Diluted
(Loss) income from continuing operations	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.51	)	$	0.63
Loss from discontinued operations, net of income taxes	—			—			—			(0.09		)	(0.19		)
Net income (loss)	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.60	)	$	0.44
Balance Sheet Data
	As at December 31,
	2017			2016			2015			2014			2013
Cash and cash equivalents	$	12,326		$	25,175		$	145,342		$	331,848		$	428,800
Working capital (deficiency)	(11,724		)	(23,344		)	160,449			239,312			244,764
Oil and gas properties	1,094,029			1,060,093			780,360			1,117,931			1,250,070
Deferred tax asset - long-term	57,310			1,611			3,241			2,153			3,663
Total assets	1,429,619			1,367,896			1,146,118			1,714,050			1,904,550
Long-term debt	256,542			197,083			—			—			—
Deferred tax liability - long-term	28,417			107,230			34,592			176,364			178,275
Total long-term liabilities	336,315			353,880			70,485			213,039			209,270
Shareholders’ equity	936,335			858,987			1,001,642			1,276,685			1,429,908

On December 18, 2017, we completed the sale of our Peru business unit. Pursuant to the divestiture, Sterling acquired all of the issued and outstanding shares of our indirect, wholly owned subsidiary that indirectly held all of our Peruvian assets for aggregate consideration of $33.5 million, comprised of approximately 187.3 million common shares of Sterling and an estimated cash-settled working capital adjustment of $0.4 million. Additionally, in connection with the divestiture, we purchased $11.0 million of subscription receipts which were exchangeable for common shares of PetroTal Ltd. and subsequently exchanged them for approximately 58.9 million common shares of Sterling. After giving effect to the divestiture, we directly and indirectly hold approximately 246.2 million common shares representing approximately 46% of Sterling's issued and outstanding common shares.

On August 23, 2016, we acquired all of the issued and outstanding common shares of PetroLatina for $525.0 million, consisting of: cash consideration of $465.7 million, which included a deferred cash payment of $25.0 million that was paid in December 31, 2016; assumption of a reserve-backed credit facility with an outstanding balance of $80.0 million; and net of working capital of $17.3 million and other closing adjustments. Upon completion of the transaction, we repaid and canceled the reserve-based credit facility and PetroLatina became an indirect wholly-owned subsidiary of Gran Tierra. The PetroLatina acquisition was funded through a combination of our existing cash balance, gross proceeds of $173.5 million from the subscription receipts offering noted below, available borrowings under our existing revolving credit facility and $130.0 million of borrowings under a bridge loan facility.

On January 25, 2016, we acquired all of the issued and outstanding common shares of PGC for cash consideration. The net purchase price of PGC was $19.4 million, after giving effect to net working capital of $18.3 million. PGC's working capital on the acquisition date included restricted cash of $18.6 million and cash of $0.2 million. All of the opening balance of restricted cash was released prior to December 31, 2016. Upon completion of the transaction, PGC became an indirect wholly-owned subsidiary of Gran Tierra.

On January 13, 2016, we acquired all of the issued and outstanding common shares of Petroamerica, a Calgary based oil and natural gas exploration, development and production company active in Colombia. As consideration, we issued approximately 13.7 million shares of Common Stock, and paid cash consideration of approximately $70.6 million. The fair value of Common Stock issued was $25.8 million based on the closing price of shares of our Common Stock on the acquisition date. The total net purchase price of Petroamerica was $72.2 million, after giving effect to net working capital of $24.2 million. Upon completion of the transaction, Petroamerica became an indirect wholly-owned subsidiary of Gran Tierra.

On June 25, 2014, we sold our Argentina business unit to Madalena Energy Inc. ("Madalena") for aggregate consideration of $69.3 million, comprising $55.4 million in cash and $13.9 million in Madalena shares. During the year ended December 31, 2016, we sold these Madalena shares. In accordance with GAAP, we met the criteria to classify our Argentina business unit as discontinued operations in the second quarter of 2014. As such, the results of operations for our Argentina business unit are reflected as loss from discontinued operations, net of income taxes.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Please see the cautionary language at the very beginning of this Annual Report on Form 10-K regarding the identification of and risks relating to forward-looking statements, as well as Part I, Item 1A. “Risk Factors” in this Annual Report on Form 10-K.

The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements and Supplementary Data” as set out in Part II, Item 8 of this Annual Report on Form 10-K.

Overview

We are a company focused on oil and gas exploration and production in Colombia. Our Colombian properties represented 100% of our proved reserves NAR at December 31, 2017. For the year ended December 31, 2017, 98% (year ended December 31, 2016 - 97%; year ended December 31, 2015 - 97%) of our revenue and other income was generated in Colombia. We are headquartered in Calgary, Alberta, Canada.

As of December 31, 2017, we had estimated proved reserves NAR of 59.3 MMBOE, of which 67% were proved developed reserves and 99% were oil.

As discussed under Items 1 and 2. “Business and Properties,” in 2017, we sold our assets in Brazil and Peru, acquired a minority interest in Sterling (which operates assets in Peru), and completed certain asset acquisitions and dispositions to further enhance our strategy.

Financial and Operational Highlights

Key Highlights


•	Increased proved and probable reserves (NAR):


◦	Proved reserves increased by 11% to 59 MMBOE at year-end 2017, up from 53 MMBOE at year-end 2016


◦	Probable reserves increased by 25% to 55 MMBOE at year-end 2017, up from 44 MMBOE at year-end 2016


•	Colombia only average production before royalties in 2017 was 31,426 BOEPD, 20% higher compared with 26,216 BOEPD in 2016.


•	Total Company 2017 average production before royalties was 32,105 BOEPD, 19% higher compared with 2016.


•	Total Company 2017 average production NAR was 26,785 BOEPD, 16% higher compared with 2016. We increased NAR production despite the sale of our Brazil assets on June 30, 2017, which had average NAR production in 2016 of 717 BOEPD, and other non-core asset sales of approximately 950 BOEPD in November 2016, largely because of production from development activities in the Acordionero Field.


•	Total Company oil and gas sales volumes for 2017 increased by 11% to 26,689 BOEPD compared with 2016.


•	Net loss in 2017 was $31.7 million compared with $465.6 million in 2016.


•	Oil and gas sales per BOE for 2017 was $43.29, 31% higher compared with 2016. Brent price increased 24% from 2016.


•	Operating expenses per BOE for 2017 was $11.28 per BOE, 14% higher compared with 2016 primarily due to expenses associated with power disruptions in the Putumayo Basin as a result of Mocoa landslide and NaturAmazonas reforestation and conservation costs.


•	Transportation expenses per BOE for 2017 decreased by 29% compared with 2016 to $2.58 per BOE due to a higher percentage of volumes sold at wellhead and the increased use of transportation routes that had lower costs than the routes used in the prior year.


•	Operating netback⁽²⁾ per BOE for 2017 was $29.43 per BOE, 51% higher compared with 2016.


•	General and administrative ("G&A") expenses before stock-based compensation per BOE for 2017 decreased by 1% compared with 2016 to $3.06 per BOE.


•	Funds flow from operations⁽²⁾ for 2017 increased by 110% to $220.2 million compared with 2016.



(Thousands of U.S. Dollars, unless otherwise noted)	Year Ended December 31,
SEC Compliant Reserves, NAR (MMBOE)	2017			% Change		2016			% Change		2015
Estimated Proved Oil and Gas Reserves	59			11		53			36		39

Estimated Probable Oil and Gas Reserves	55			25		44			175		16

Estimated Possible Oil and Gas Reserves	58			(9	)	64			392		13

Average Daily Volumes (BOEPD)
Consolidated
Working Interest Production Before Royalties	32,105			19		27,062			16		23,401
Royalties	(5,320		)	37		(3,875		)	(1	)	(3,912		)
Production NAR	26,785			16		23,187			19		19,489
(Increase) Decrease in Inventory	(96		)	(113	)	767			(162	)	(1,229		)
Sales⁽¹⁾	26,689			11		23,954			31		18,260

Colombia
Working Interest Production Before Royalties	31,426			20		26,216			15		22,794
Royalties	(5,217		)	39		(3,746		)	(2	)	(3,822		)
Production NAR	26,209			17		22,470			18		18,972
(Increase) Decrease in Inventory	(101		)	(113	)	771			(163	)	(1,231		)
Sales⁽¹⁾	26,108			12		23,241			31		17,741

Net Loss	$	(31,708	)	93		$	(465,565	)	(74	)	$	(268,029	)

Operating Netback
Oil and Natural Gas Sales	$	421,734		46		$	289,269		5		$	276,011
Operating Expenses	(109,869		)	26		(86,925		)	15		(75,565		)
Transportation Expenses	(25,107		)	(21	)	(31,776		)	(21	)	(40,204		)
Operating Netback⁽²⁾	$	286,758		68		$	170,568		6		$	160,242

G&A Expenses Before Stock-Based Compensation	$	29,775		10		$	27,127		(9	)	$	29,780
G&A Stock-Based Compensation	$	9,239		52		$	6,091		137		$	2,573

Adjusted EBITDA⁽²⁾	$	248,005		93		$	128,414		13		$	113,252

Funds Flow From Operations⁽²⁾	$	220,197		110		$	104,984		(2	)	$	107,570

Capital Expenditures	$	251,041		96		$	127,789		(18	)	$	156,639

Net Cash Received on Dispositions	$	32,968		—		$	—		—		$	—

Cash Paid for Acquisitions, Net of Cash Acquired	$	34,410		(93	)	$	507,584		—		$	—



	As at December 31,
(Thousands of U.S. Dollars)	2017		% Change		2016		% Change		2015
Cash, Cash Equivalents and Current Restricted Cash and Cash Equivalents	$	24,113	(28	)	$	33,497	(77	)	$	145,434

Revolving Credit Facility	$	148,000	64		$	90,000	—		$	—

Convertible Senior Notes	$	115,000	—		$	115,000	—		$	—

⁽¹⁾ Sales volumes represent production NAR adjusted for inventory changes.

⁽²⁾Non-GAAP measures

Operating netback, adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or loss or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as oil and natural gas sales less operating and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil and natural gas sales to operating netback is provided in the table above.

Adjusted EBITDA, as presented, is defined as net loss adjusted for depletion, depreciation and accretion ("DD&A") expenses, asset impairment, interest expense, income tax recovery or expense, unrealized financial instruments loss or gain, loss on sale of business units and gain on acquisition, and foreign exchange gains and losses. Management uses this supplemental measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net loss to adjusted EBITDA is as follows:



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016			2015
Net loss	$	(31,708	)	$	(465,565	)	$	(268,029	)
Adjustments to reconcile net loss to adjusted EBITDA
DD&A expenses	131,335			139,535			176,386
Asset impairment	1,514			616,649			323,918
Interest expense	13,882			14,145			—
Income tax expense (recovery)	69,038			(184,669		)	(100,059		)
Unrealized financial instruments loss (gain)	17,492			10,717			(1,722		)
Loss on sale of business units and (gain) on acquisition	44,385			(929		)	—
Foreign exchange loss (gain)	2,067			(1,469		)	(17,242		)
Adjusted EBITDA (non-GAAP)	$	248,005		$	128,414		$	113,252

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, cash settlement of RSUs, unrealized foreign exchange and financial instruments gains and losses, loss on sale of business units or gain on acquisition and other gain. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to funds flow from operations is as follows:



	Fourth Quarter			Third Quarter			Fourth Quarter			Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2017			2016			2017			2016			2015
Net income (loss)	$	(40,802	)	$	3,130		$	(127,355	)	$	(31,708	)	$	(465,565	)	$	(268,029	)
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	38,606			34,492			35,010			131,335			139,535			176,386
Asset impairment	275			787			146,934			1,514			616,649			323,918
Deferred tax expense (recovery)	8,052			13,760			(38,589		)	44,716			(204,791		)	(115,442		)
Stock-based compensation expense	4,840			1,752			1,959			9,775			6,339			2,733
Amortization of debt issuance costs	547			643			2,878			2,415			5,691			—
Cash settlement of RSUs	(30		)	(33		)	(24		)	(564		)	(1,234		)	(1,392		)
Unrealized foreign exchange loss (gain)	1,141			(1,380		)	(3,865		)	837			(1,428		)	(8,380		)
Financial instruments loss	21,140			1,675			8,455			15,929			10,279			2,027
Cash settlement of financial instruments	45			302			—			1,563			438			(3,749		)
Loss on sale of business units and (gain) on acquisition	35,309			—			10,783			44,385			(929		)	—
Other gain	—			—			—			—			—			(502		)
Funds flow from operations (non-GAAP)	$	69,123		$	55,128		$	36,186		$	220,197		$	104,984		$	107,570

Consolidated Results of Operations



	Year Ended December 31,
	2017			% Change		2016			% Change		2015
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	421,734		46		$	289,269		5		$	276,011
Operating expenses	109,869			26		86,925			15		75,565
Transportation expenses	25,107			(21	)	31,776			(21	)	40,204
Operating netback⁽¹⁾	286,758			68		170,568			6		160,242

DD&A expenses	131,335			(6	)	139,535			(21	)	176,386
Asset impairment	1,514			(100	)	616,649			90		323,918
G&A expenses before stock-based compensation	29,775			10		27,127			(9	)	29,780
G&A stock-based compensation expense	9,239			52		6,091			137		2,573
Severance expenses	1,287			(2	)	1,319			(85	)	8,990
Transaction expenses	—			(100	)	7,325			—		—
Equity tax	1,224			(60	)	3,098			(18	)	3,769
Foreign exchange loss (gain)	2,067			241		(1,469		)	91		(17,242		)
Financial instruments loss	15,929			55		10,279			407		2,027
Other gain	—			—		—			100		(502		)
Interest expense	13,882			(2	)	14,145			—		—
	206,252			(75	)	824,099			56		529,699

(Loss) on sale of business units and gain on acquisition	(44,385		)	—		929			—		—
Interest income	1,209			(49	)	2,368			73		1,369

Income (loss) before income taxes	37,330			106		(650,234		)	(77	)	(368,088		)

Current income tax expense	24,322			21		20,122			31		15,383
Deferred income tax expense (recovery)	44,716			122		(204,791		)	(77	)	(115,442		)



	69,038			137		(184,669		)	(85	)	(100,059		)
Net loss	$	(31,708	)	93		$	(465,565	)	(74	)	$	(268,029	)

Sales Volumes (NAR)
Total sales volumes, BOEPD	26,689			11		23,954			31		18,260

Average Prices
Oil and NGL's per bbl	$	43.66		31		$	33.22		(20	)	$	41.56
Natural gas per Mcf	$	1.90		(14	)	$	2.22		(42	)	$	3.80

Brent Price per bbl	$	54.82		24		$	44.33		(15	)	$	52.35

Consolidated Results of Operations per BOE Sales Volumes (NAR)
Oil and natural gas sales	$	43.29		31		$	33.00		(20	)	$	41.41
Operating expenses	11.28			14		9.92			(13	)	11.34
Transportation expenses	2.58			(29	)	3.62			(40	)	6.03
Operating netback⁽¹⁾	29.43			51		19.46			(19	)	24.04

DD&A expenses	13.48			(15	)	15.92			(40	)	26.47
Asset impairment	0.16			(100	)	70.34			45		48.60
G&A expenses before stock-based compensation	3.06			(1	)	3.10			(30	)	4.46
G&A stock-based compensation expense	0.95			38		0.69			77		0.39
Severance expenses	0.13			(13	)	0.15			(89	)	1.35
Transaction expenses	0.00			(100	)	0.84			—		0.00
Equity tax	0.13			(63	)	0.35			(39	)	0.57
Foreign exchange loss (gain)	0.21			224		(0.17)			93		(2.59)
Financial instruments loss	1.64			40		1.17			290		0.30
Other gain	—			—		—			(100	)	(0.08		)
Interest expense	1.43			(11	)	1.61			—		—
	21.19			77		94.00			(18	)	79.47

(Loss) on sale of business units and gain on acquisition	(4.56		)	—		0.11			—		—
Interest income	0.12			(56	)	0.27			29		0.21

Income (loss) before income taxes	3.80			105		(74.16		)	(34	)	(55.22		)

Current income tax expense	2.50			9		2.30			—		2.31
Deferred income tax expense (recovery)	4.59			120		(23.36)			(35	)	(17.32)
	7.09			134		(21.06)			(40	)	(15.01)
Net loss	$	(3.29	)	94		$	(53.10	)	(32	)	$	(40.21	)

⁽¹⁾ Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to "Financial and Operating Highlights - non-GAAP measures" for a definition and reconciliation of this measure.

Oil and Gas Production and Sales Volumes, BOEPD



	Year Ended December 31,
Average Daily Volumes (BOEPD) - Colombia	2017		2016		2015
Working Interest Production Before Royalties	31,426		26,216		22,794
Royalties	(5,217	)	(3,746	)	(3,822	)
Production NAR	26,209		22,470		18,972
(Increase) Decrease in Inventory	(101	)	771		(1,231	)
Sales	26,108		23,241		17,741

Royalties, % of Working Interest Production Before Royalties	17	%	14	%	17	%

	Year Ended December 31,
Average Daily Volumes (BOEPD) - Brazil	2017		2016		2015
Working Interest Production Before Royalties	679		846		607
Royalties	(103	)	(129	)	(90	)
Production NAR	576		717		517
Decrease (Increase) in Inventory	5		(4	)	2
Sales	581		713		519

Royalties, % of Working Interest Production Before Royalties	15	%	15	%	15	%

	Year Ended December 31,
Average Daily Volumes (BOEPD) - Total	2017		2016		2015
Working Interest Production Before Royalties	32,105		27,062		23,401
Royalties	(5,320	)	(3,875	)	(3,912	)
Production NAR	26,785		23,187		19,489
(Increase) Decrease in Inventory	(96	)	767		(1,229	)
Sales	26,689		23,954		18,260

Royalties, % of Working Interest Production Before Royalties	17	%	14	%	17	%

Oil and gas production NAR for the year ended December 31, 2017 increased by 16% to 26,785 BOEPD compared with 23,187 BOEPD in 2016. We increased oil and gas production NAR despite the sale of our Brazil business unit on June 30, 2017. Production increased as a result of a successful drilling and workover campaign in the Acordionero Field in Colombia, the successful Vonu-1 exploration well and a workover campaign in Cumplidor. Colombian NAR production for the year ended December 31, 2017 increased 17% compared with the prior year.

Royalties as a percentage of production for the year ended December 31, 2017 increased compared to prior year commensurate with the increase in oil prices, due to price sensitive royalties payable in Colombia.

Oil and gas production NAR for the year ended December 31, 2016 increased by 19% to 23,187 BOEPD compared with 19,489 BOEPD in 2015. Production increased as a result of the Petroamerica and PetroLatina acquisitions and a successful drilling campaign in the Costayaco, Moqueta and Acordionero Fields in Colombia.

Operating Netbacks



Colombia	Year Ended December 31,
(Thousands of U.S. Dollars)	2017		2016		2015
Oil and Natural Gas Sales	$	413,316	$	280,872	$	269,035



Transportation Expenses	(24,757		)	(31,347		)	(40,083		)
	388,559			249,525			228,952
Operating Expenses	(108,072		)	(84,794		)	(69,323		)
Operating Netback⁽¹⁾	$	280,487		$	164,731		$	159,629

(U.S. Dollars per BOE Sales Volumes NAR)
Brent	$	54.82		$	44.33		$	52.35
Quality and Transportation Discounts	(11.45		)	(11.31		)	(10.80		)
Average Realized Price	43.37			33.02			41.55
Transportation Expenses	(2.60		)	(3.69		)	(6.19		)
Average Realized Price Net of Transportation Expenses	40.77			29.33			35.36
Operating Expenses	(11.34		)	(9.97		)	(10.71		)
Operating Netback⁽¹⁾	$	29.43		$	19.36		$	24.65

Brazil	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016			2015
Oil and Natural Gas Sales	$	8,418		$	8,397		$	6,976
Transportation Expenses	(350		)	(429		)	(121		)
	8,068			7,968			6,855
Operating Expenses	(1,797		)	(2,131		)	(6,242		)
Operating Netback⁽¹⁾	$	6,271		$	5,837		$	613

(U.S. Dollars per BOE Sales Volumes NAR)
Brent	$	54.82		$	44.33		$	52.35
Quality and Transportation Discounts	(15.06		)	(12.11		)	(15.51		)
Average Realized Price	39.76			32.22			36.84
Transportation Expenses	(1.65		)	(1.65		)	(0.64		)
Average Realized Price Net of Transportation Expenses	38.11			30.57			36.20
Operating Expenses	(8.49		)	(8.18		)	(32.97		)
Operating Netback⁽¹⁾	$	29.62		$	22.39		$	3.23

Total	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016			2015
Oil and Gas Sales	$	421,734		$	289,269		$	276,011
Transportation Expenses	(25,107		)	(31,776		)	(40,204		)
	396,627			257,493			235,807
Operating Expenses	(109,869		)	(86,925		)	(75,565		)
Operating Netback⁽¹⁾	$	286,758		$	170,568		$	160,242

(U.S. Dollars per BOE Sales Volumes NAR)
Brent	$	54.82		$	44.33		$	52.35
Quality and Transportation Discounts	(11.53		)	(11.33		)	(10.94		)
Average Realized Price	43.29			33.00			41.41
Transportation Expenses	(2.58		)	(3.62		)	(6.03		)
Average Realized Price Net of Transportation Expenses	40.71			29.38			35.38
Operating Expenses	(11.28		)	(9.92		)	(11.34		)
Operating Netback⁽¹⁾	$	29.43		$	19.46		$	24.04

(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operating Highlights - non-GAAP measures” for a definition and reconciliation of this measure.

Oil and gas sales for the year ended December 31, 2017 increased to $421.7 million from $289.3 million in 2016 primarily as a result of the effect of increased sales volumes and realized oil prices. Oil and gas sales for the year ended December 31, 2016 increased to $289.3 million from $276.0 million in 2015 primarily as a result of the effect of increased volumes, partially offset by decreased average realized oil prices.

The following table shows the effect of changes in realized price and sales volumes on our oil and gas sales for the three years ended December 31, 2017:



	Year Ended December 31,
	2017		2016
Oil and natural gas sales for the comparative period	$	289,269	$	276,011
Realized sales price increase (decrease) effect	100,304		(73,782		)
Sales volume increase effect	32,161		87,040
Oil and natural gas sales for the current period	$	421,734	$	289,269

Average realized prices increased by 31% to $43.29 per BOE for the year ended December 31, 2017 from $33.00 per BOE in 2016. The increase in realized prices was consistent with an increase in benchmark oil prices. Average Brent oil prices for the year ended December 31, 2017 increased by 24% compared with 2016.

Average realized prices decreased by 20% to $33.00 per BOE for the year ended December 31, 2016, from $41.41 per BOE in 2015. The decrease in realized prices was consistent with lower benchmark oil prices. Average Brent oil prices for the year ended December 31, 2016 decreased by 15% compared with 2015.

We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized prices and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for each of the three years ended December 31, 2017:



	Year Ended December 31,
	2017		2016		2015
Volume sold transported through pipelines	16	%	44	%	54	%
Volume sold at wellhead, trucking	52	%	43	%	30	%
Volume sold not at wellhead, trucking	32	%	13	%	16	%
	100	%	100	%	100	%

Volumes not sold at the wellhead receive a higher realized price, but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense.

Transportation expenses for the year ended December 31, 2017 decreased by 21% to $25.1 million, compared with $31.8 million in 2016. On a per BOE basis, transportation expenses decreased 29% to $2.58 per BOE from $3.62 per BOE, in 2016. The decrease in transportation expenses per BOE was primarily due to a higher percentage of volumes sold at wellhead, as noted in the table above, and the use of alternative transportation routes, which had lower costs per BOE than the routes used in 2016.

Transportation expenses for the year ended December 31, 2016 decreased 21% to $31.8 million, compared with $40.2 million in 2015. On a per BOE basis, transportation expenses decreased 40% to $3.62 per BOE from $6.03 per BOE, in 2015. The decrease in transportation expenses per BOE was primarily due to a higher percentage of volumes sold at wellhead, as noted in the table above, and the use of alternative transportation routes, which had lower costs per BOE than the routes used in 2015.

The following table shows the variance in our average realized prices net of transportation expenses in Colombia for each of the three years ended December 31, 2017:



	Year Ended December 31,
(U.S. Dollars per BOE Sales Volumes NAR)	2017			2016			2015
Average realized price net of transportation expenses for the comparative period	$	29.33		$	35.36		$	79.07
Increase (decrease) in benchmark prices	10.49			(8.02		)	(46.67		)
(Increase) decrease in quality and transportation discounts	(0.14		)	(0.51		)	5.46
Decrease (increase) in transportation expense	1.09			2.50			(2.50		)
Average realized price net of transportation expenses for the year	$	40.77		$	29.33		$	35.36

Operating expenses for the year ended December 31, 2017 increased 26% to $109.9 million compared with $86.9 million in 2016. The increase was primarily due to higher sales volumes and an increase in operating costs per BOE.

In Colombia, operating costs for the year ended December 31, 2017 increased by $1.37 per BOE compared with 2016, primarily as a result of power disruptions in the Putumayo region relating to the Mocoa natural disaster and NaturAmazonas reforestation expenses.

As previously reported in our Quarterly Report on Form 10-Q filed with the SEC on August 4, 2017, since the Mocoa natural disaster, the electrical system in the Putumayo region has experienced instability, and we have had to utilize gas and diesel generators to maintain production and injection at key wells during brief periods of electrical outage. The instability of electricity not only increases our operating costs it also has a negative impact on our production in the Putumayo Basin and water injection program in both Costayaco and Moqueta. We are expanding a gas to electrical power facility in Costayaco which will enable consistent power generation.

On January 30, 2017, we signed an agreement with Conservation International to launch NaturAmazonas, a five year reforestation and conservation program to be implemented by Conservation International in the Putumayo Region of Colombia. Conservation International is a non-government organization, well-known for implementing and managing nature conservation projects around the world. During the year ended December 31, 2017, operating expenses included $3.2 million related to this program.

Operating expenses for the year ended December 31, 2016 were $86.9 million, or $9.92 per BOE, compared with $75.6 million, or $11.34 per BOE in 2015. On a per BOE basis, operating expenses decreased by 13%. The decrease in operating expenses per BOE in 2016 was primarily due to Colombian operating cost savings, partially offset by the effect of the weakening of the U.S. dollar against local currencies in South America. Workover expenses increased by $0.38 per BOE to $2.60 per BOE compared with the year ended December 31, 2015. Excluding workover expenses, operating costs decreased by $1.80 per BOE to $7.32 per BOE.

Colombian operating expenses for the year ended December 31, 2016 decreased by $0.74 per BOE compared with the corresponding period in 2015. Workover expenses increased by $0.38 per BOE. Excluding workover expenses, operating expenses in Colombia decreased by $1.12 per BOE.

DD&A Expenses



	Year Ended December 31, 2017				Year Ended December 31, 2016
	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	$	126,453	$	13.27	$	132,569	$	15.59
Brazil	2,263		10.69		3,819		14.65
Peru	1,483		—		544		—
Corporate	1,136		—		2,603		—
	$	131,335	$	13.48	$	139,535	$	15.92

	Year Ended December 31, 2015
	DD&A expenses, thousands of U.S. Dollars		DD&A expenses, U.S. Dollars Per BOE
Colombia	$	167,701	$	25.90
Brazil	6,183		32.66
Peru	789		—
Corporate	1,713		—
	$	176,386	$	26.47

DD&A expenses for the year ended December 31, 2017 decreased to $131.3 million ($13.48 per BOE) from $139.5 million ($15.92 per BOE) in 2016, and from $176.4 million ($26.47 per BOE) in 2015. On a per BOE basis, the decreases in both years were due to increased proved reserves at year-end and lower costs in the depletable base in 2016.

Asset Impairment



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017		2016		2015
Impairment of oil and gas properties
Colombia	$	—	$	513,650	$	232,436
Brazil	—		71,143		46,933
Peru	890		31,192		41,916
Mexico	624		—		—
	1,514		615,985		321,285
Impairment of inventory	—		664		2,633
	$	1,514	$	616,649	$	323,918

We follow the full cost method of accounting for our oil and gas properties. 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. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of our reserves.

In the year ended December 31, 2017, no ceiling test impairment was recorded in our Colombia cost center. In accordance with GAAP, we used an average Brent price of $54.19 per bbl for the purposes of the December 31, 2017, ceiling test calculation

(September 30, 2017 - $52.70; June 30, 2017 - $51.35, March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48, March 31, 2016 - $48.79; December 31, 2015 - $54.08).

In the year ended December 31, 2016, ceiling test impairment losses in our Colombia cost center and inventory impairment losses were primarily due to lower oil prices and because the acquisitions of PetroLatina and PetroAmerica were initially added into the cost base at fair value. These acquired assets were then subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which, as noted above, uses constant commodity pricing that averages prices during the preceding 12 months. The ceiling test impairment loss in our Brazil cost center related to lower oil prices and increased costs in the depletable base as a result of a $45.0 million impairment of unproved properties. Impairment losses in our Peru cost center included costs incurred on Block 95 and an impairment of costs incurred on Blocks 123 and 129.

In the year ended December 31, 2015, ceiling test impairment losses in our Colombia and Brazil cost centers and inventory impairment losses were primarily due to lower oil prices. Impairment losses in our Peru cost center related to costs incurred on Block 95.

G&A Expenses



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017		% change		2016		% change		2015
G&A Expenses Before Stock-Based Compensation	$	29,775	10	%	$	27,127	(9	)%	$	29,780
G&A Stock-Based Compensation	9,239		52	%	6,091		137	%	2,573
G&A Expenses, Including Stock-Based Compensation	$	39,014	17	%	$	33,218	3	%	$	32,353

U.S. Dollars Per BOE Sales Volumes NAR
G&A Expenses Before Stock-Based Compensation	$	3.06	(1	)%	$	3.10	(30	)%	$	4.46
G&A Stock-Based Compensation	0.95		38	%	0.69		77	%	0.39
G&A Expenses, Including Stock-Based Compensation	$	4.01	6	%	$	3.79	(22	)%	$	4.85

G&A expenses before stock-based compensation for the year ended December 31, 2017 increased by 10% to $29.8 million ($3.06 per BOE) from $27.1 million ($3.10 per BOE) in 2016. The increase was commensurate with our growth. Since December 31, 2016, we drilled 25 wells and grew production NAR 16% from 23,187 BOEPD in 2016 to 26,785 BOEPD in 2017. G&A expenses before stock-based compensation per BOE was consistent with 2016 and decreased 31% from 2015. After stock-based compensation, G&A expenses for the year ended December 31, 2017 increased by 17% to $39.0 million from $33.2 million in 2016. The increase was mainly as a result of PSUs and DSUs granted during 2017 combined with the increase in the stock price during the fourth quarter of 2017.

G&A expenses before stock-based compensation for the year ended December 31, 2016 decreased by 9% to $27.1 million ($3.10 per BOE) from $29.8 million ($4.46 per BOE) in 2015. These decreases were mainly due to savings due to cost control initiatives. After stock-based compensation, G&A expenses for the year ended December 31, 2016 increased by 3% to $33.2 million ($3.79 per BOE) from $32.4 million ($4.85 per BOE) in 2015. The increase was mainly as a result of Performance Stock Units (“PSUs”) and deferred share units (“DSUs”) granted during 2016 and a higher year-end share price.

Severance Expenses

For the year ended December 31, 2017, severance expenses were $1.3 million compared with $1.3 million and $9.0 million, respectively, in 2016 and 2015. Severance expenses were consistent with the decrease in headcount.

Transaction Expenses

For the year ended December 31, 2017, transaction expenses were nil, compared with $7.3 million in 2016 and nil in 2015. Transaction expenses in 2016 related to our acquisitions of PetroLatina and Petroamerica.

Equity Tax Expense

For the years ended December 31, 2017, 2016 and 2015, equity tax expense was $1.2 million, $3.1 million and $3.8 million, respectively, and was calculated based on our Colombian legal entities' balance sheet at January 1.

Foreign Exchange Gains and Losses

For the years ended December, 2017, 2016 and 2015, we had foreign exchange losses of $2.1 million and gains of $1.5 million and $17.2 million, respectively. Under GAAP, deferred taxes are considered a monetary liability and require translation from local currency to U.S. dollar functional currency at each balance sheet date. This translation was the main source of the foreign exchange losses and gains.

The following table presents the change in the Colombian peso against the U.S. dollar for each of the three years ended December 31, 2017:



	Year Ended December 31,
	2017	2016	2015
Change in the Colombian peso against the U.S. dollar	strengthened by	strengthened by	weakened by
Change in the Colombian peso against the U.S. dollar	1%	5%	32%

Financial Instrument Gains and Losses

The following table presents the nature of our financial instruments gains and losses for each of the three years ended December 31, 2017:



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016			2015
Commodity price derivative loss	$	17,327		$	7,370		$	—
Foreign currency derivative (gain) loss	(1,287		)	(1,016		)	692
Investment gain	(111		)	—			—
Trading securities loss	—			3,925			1,335
	$	15,929		$	10,279		$	2,027

Loss on Sale of Business Units and Gain on Acquisition

Loss on sale of business units for the year ended December 31, 2017, related to the sale of our Brazil business unit on June 30, 2017 and our Peru business unit on December 18, 2017. Gain on acquisition for the year ended December 31, 2016, related to the acquisition of Petroamerica.

Income Tax Expense and Recovery



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016			2015
Income (loss) before income tax	$	37,330		$	(650,234	)	$	(368,088	)

Current income tax expense	$	24,322		$	20,122		$	15,383
Deferred income tax expense (recovery)	44,716			(204,791		)	(115,442		)
Total income tax expense (recovery)	$	69,038		$	(184,669	)	$	(100,059	)

Effective tax rate	185		%	28		%	27		%

Deferred income tax recovery related to Colombia ceiling test impairment	$	—		$	201,300		$	91,700

Current income tax expense was higher in the year ended December 31, 2017, compared with 2016 and 2015 primarily as a result of higher taxable income in Colombia.

The deferred income tax expense for the year ended December 31, 2017 of $44.7 million was primarily a result of tax depreciation being higher than accounting depreciation in Colombia. In general, tax depreciation for capital expenditures investments incurred prior to 2017 is straight line over five years and accounting depreciation is based on the unit of production method. The deferred income tax recovery in the years ended December 31, 2016 and 2015 of $204.8 million and $115.4 million, respectively, were due to ceiling test impairment losses in Colombia. In 2016 and 2015, income tax recovery associated with impairment losses in Brazil and Peru was offset by a full valuation allowance.

Our effective tax rate was 185% for the year ended December 31, 2017, compared with 28% in 2016. The increase in the effective tax rate was primarily due to the increase in the impact of foreign taxes, mainly as a result of the difference between the tax rates in Colombia and US and applying this difference to a deferred tax expense during 2017 versus a deferred tax recovery during 2016; increase in the valuation allowance mainly due to $20.9 million of foreign tax credits in the US arising from the US legislated one-time deemed repatriation of foreign earnings; non-deductible third-party royalty in Colombia; and, stock based compensation. These were partially offset by decreases resulting from the sale of Brazil and Peru, other local taxes, and other permanent differences.

Our effective tax rate was 28% for the year ended December 31, 2016 compared with 27% in 2015. The increase in the effective tax rate was primarily due to a decrease in other permanent differences; non-deductible third party royalties; and, other local taxes. These were partially offset by an increase in the valuation allowance, the effect of foreign taxes, stock based compensation and foreign currency translation adjustments.

The difference between our effective tax rate of 185% for the year ended December 31, 2017, and the 35% U.S. statutory rate was primarily due to due to an increase in the valuation allowance, mainly due to $20.9 million of foreign tax credits in the US arising from the US legislated one-time deemed repatriation of foreign earnings, $86.7 million of capital losses generated in Luxembourg as a result of the sale of Brazil, and $8.5 million of tax losses and tax credits generated in one of the entities in Colombia; the impact of foreign taxes, mainly due to the tax rate differential with Colombia; non-deductible third-party royalty in Colombia; stock based compensation; and, other local taxes. These were partially offset by decreases as a result of capital losses generated from the sale of Brazil, and other permanent differences.

The difference between our effective tax rate of 28% for the year ended December 31, 2016, and the 35% U.S. statutory rate was primarily due to an increase in the valuation allowance; non-deductible third party royalties in Colombia; other local taxes, and, stock based compensation. These were partially offset by the impact of foreign taxes and other permanent differences.

Net Loss and Funds Flow From Operations (a Non-GAAP Measure)



(Thousands of U.S. Dollars)	Fourth quarter 2017 compared with third quarter 2017			% change		Fourth quarter 2017 compared with fourth quarter 2016			% change		Year ended December 31, 2017 compared with year ended December 31, 2016			% change
Net income (loss) for the comparative period	$	3,130				$	(127,355	)			$	(465,565	)
Increase (decrease) due to:
Sales volumes	2,732					5,857					32,161
Prices	20,679					29,708					100,304
Expenses:
Operating	(4,082		)			(6,931		)			(22,944		)
Transportation	403					1,823					6,669
Cash G&A and RSU settlements, excluding stock-based compensation expense	(396		)			3,341					(1,690		)
Transaction	—					—					7,325
Severance	1,041					(103		)			32
Interest, net of amortization of debt issuance costs	426					505					(3,013		)
Realized foreign exchange	(36		)			1,190					(1,270		)
Settlement of financial instruments	(257		)			45					1,125
Current taxes	(6,467		)			(2,358		)			(4,200		)
Equity tax	—					45					1,874
Other	(48		)			(185		)			(1,160		)
Net change in funds flow from operations⁽¹⁾ from comparative period	13,995					32,937					115,213
Expenses:
Depletion, depreciation and accretion	(4,114		)			(3,596		)			8,200
Asset impairment	512					146,659					615,135
Deferred tax	5,708					(46,641		)			(249,507		)
Amortization of debt issuance costs	96					2,331					3,276
Stock-based compensation, net of RSU settlement	(3,091		)			(2,875		)			(4,106		)
Financial instruments gain or loss, net of financial instruments settlements	(19,208		)			(12,730		)			(6,775		)
Unrealized foreign exchange	(2,521		)			(5,006		)			(2,265		)
Loss on sale of business units and gain on acquisition	(35,309		)			(24,526		)			(45,314		)
Net change in net income or loss	(43,932		)			86,553					433,857
Net loss for the current period	$	(40,802	)	1,404	%	$	(40,802	)	68	%	$	(31,708	)	93	%

(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to “Financial and Operating Highlights - non-GAAP measures” for a definition and reconciliation of this measure.

2018 Capital Program

Colombia remains our primary focus and represents 100% of the 2018 capital program. In December 2017, we announced our 2018 capital budget. We expect the following ranges for our 2018 capital budget:



	Number of Wells (Gross)	Number of Wells (Net)	2018 Capital Budget ($ million)
Colombia
Development	19-21	18-20	100-105
Exploration	8-11	7-10	80-90
Facilities	—	—	50-55
Seismic and Studies	—	—	20
	27-32	25-30	250-270

We expect our 2018 capital program to be fully funded through cash flows from operations.

2017 Capital Program

Capital expenditures during the year ended December 31, 2017, were $251.0 million:



(Thousands of U.S. Dollars)
Colombia	$	242,636
Brazil	2,811
Peru	4,483
Corporate	1,111
	$	251,041

During the year ended December 31, 2017, we spud the following wells in Colombia:



	Number of wells (Gross)	Number of wells (Net)
Development	21	17.3
Exploration	4	3.6
Total Colombia	25	20.9

We spud exploration wells in the Putumayo-1 Block (Vonu-1), Putumayo-7 Block (Confianza-1), Putumayo-4 Block (Siriri-1) and Midas Block (Ayombero-1). Two of these wells are currently on production (Vonu-1 and Confianza-1) and we are currently evaluating Siriri and testing Ayombero.

Development wells were spud in the Midas Block (Acordionero-9, 10i, 11, 12, 13, 14i, 15, 16, 17, 18, 20, 21 and Mochuelo), Suroriente Block (Cohembi-19, 20, 21, 22), Chaza Block (Costayaco-28, 29 and 30) and Guayuyaco Block (Juanambu-2). Two of these wells were water injection wells (Acordionero-10i and 14i).

We also continued facilities work at the Acordionero Field on the Midas Block and the Moqueta Field on the Chaza Block.

In Brazil up to the date of sale on June 30, 2017, we commenced work on a water injection/pressure support project with a workover on a well in the Tie Field to assess its potential as a water source well and we continued facility improvements, including the completion of a compressed natural gas project and a flare stack.

In Peru, up to the date of sale on December 18, 2017, we continued work activities relating to maintaining tangible asset integrity and security of our five blocks in Peru and to forward environmental approvals on two of these blocks. Since that date, we have owned a minority equity interest in Sterling, which owns and operates assets in Peru. Please read “2017 Overview - Acquisitions and Dispositions” in Items 1 and 2. “Business and Properties.”

Liquidity and Capital Resources



	As at December 31,
(Thousands of U.S. Dollars)	2017		% Change		2016		% Change		2015
Cash and Cash Equivalents	$	12,326	(51	)	$	25,175	(83	)	$	145,342

Current Restricted Cash and Cash Equivalents	$	11,787	42		$	8,322	—		$	92

Revolving Credit Facility	$	148,000	64		$	90,000	—		$	—

Convertible Senior Notes	$	115,000	—		$	115,000	—		$	—

We believe that our capital resources, including cash on hand, cash generated from operations and available capacity on our credit facility, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for 2018, given current oil price trends and production levels. We may also opportunistically access the capital markets. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions.

On February 15, 2018, through our indirect wholly owned subsidiary, Gran Tierra Energy International Holdings Ltd., we issued $300 million aggregate principal amount of 6.25% Senior Notes due 2025 (the "2025 Notes") in a private placement transaction. The 2025 Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 2025 Notes will mature on February 15, 2025, unless earlier redeemed or repurchased. The net proceeds of the 2025 Notes were used to repay the outstanding amount on the revolving credit facility, with the remainder for general corporate purposes.

At December 31, 2017, we had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. The next re-determination of the borrowing base is due to occur no later than May 2018.

Under the terms of our credit facility we are required to maintain compliance with certain financial and operating covenants which include: the maintenance of a ratio of debt, including letters of credit, to net income plus interest, taxes, depreciation, depletion, amortization, exploration expenses and all non-cash charges minus all non-cash income (as defined in our credit agreement, "EBITDAX") not to exceed 4.0 to 1.0; the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. As at December 31, 2017, we were in compliance with all financial and operating covenants in our credit agreement. Under the terms of the credit facility, we are limited in our ability to pay any dividends to our shareholders without bank approval.

We have, at December 31, 2017, $115 million aggregate principal amount of 5.00% Convertible Senior Notes due 2021 (the "Convertible Notes") outstanding. The Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year. The Convertible Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. The Convertible Notes are convertible to Common Stock at a conversion price of approximately $3.21 per share of Common Stock at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date.

Cash and Cash Equivalents Held Outside of Canada and the United States

At December 31, 2017, 93% of our cash and cash equivalents were held by subsidiaries and partnerships outside of Canada and the United States. This cash was generally not available to fund domestic or head office operations unless funds were repatriated. At this time, we do not intend to repatriate further funds, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.

Derivative Positions

At December 31, 2017, we had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: January 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: January 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

A participating swap provides firm downside protection at the swap price and allows us to participate in any upside over and above the call price.

At December 31, 2017, we had outstanding foreign currency derivative positions as follows:



Period and type of instrument	Amount hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: January 1, 2018 to December 31, 2018	174,000	58,311	COP	3,000	3,107

Cash Flows

The following table presents our sources and uses of cash and cash equivalents for the periods presented:



	Year Ended December 31,
	2017			2016			2015
Sources of cash and cash equivalents:
Net loss	$	(31,708	)	$	(465,565	)	$	(268,029	)
Adjustments to reconcile net loss to funds flow from operations
DD&A expenses	131,335			139,535			176,386
Asset impairment	1,514			616,649			323,918
Deferred tax expense (recovery)	44,716			(204,791		)	(115,442		)
Stock-based compensation expense	9,775			6,339			2,733
Amortization of debt issuance costs	2,415			5,691			—
Cash settlement of RSUs	(564		)	(1,234		)	(1,392		)
Unrealized foreign exchange loss (gain)	837			(1,428		)	(8,380		)
Financial instruments loss	15,929			10,279			2,027
Cash settlement of financial instruments	1,563			438			(3,749		)
Other gain	—			—			(502		)
Loss on sale of business units and (gain) on acquisition	44,385			(929		)	—
Funds flow from operations⁽¹⁾	220,197			104,984			107,570
Proceeds from other debt, net of issuance costs	167,043			256,065			—
Proceeds from oil and gas properties	—			6,000			—
Changes in non-cash investing working capital	19,680			21,116			—
Proceeds from sale of marketable securities	—			2,325			—
Net proceeds from sale of business units	32,968			—			—
Proceeds from issuance of Common Stock, net of issuance costs	—			128,273			722
Proceeds from issuance of subscription receipts, net of issuance costs	—			165,805			—
Proceeds from issuance of Convertible Notes, net of issuance costs	—			109,090			—
Foreign exchange gain on cash, cash equivalents and restricted cash and cash equivalents	—			354			—
	439,888			794,012			108,292

Uses of cash and cash equivalents:
Acquisitions of PetroLatina and PetroAmerica, net of cash acquired	—			(488,196		)	—
Additions to property, plant and equipment - property acquisitions	(34,410		)	(19,388		)	—
Additions to property, plant and equipment, excluding PGC acquisition	(251,041		)	(127,789		)	(156,639		)
Repayment of debt	(110,000		)	(252,181		)	—
Cash paid for investments	(11,000		)	—			—
Changes in non-cash investing working capital	—			—			(76,844		)
Changes in non-cash operating working capital	(29,217		)	(11,337		)	(39,048		)
Cash settlement of asset retirement obligation	(1,336		)	(605		)	(6,217		)
Repurchase of shares of Common Stock	(17,916		)	—			(9,999		)
Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(1,557		)	—			(6,516		)
	(456,477		)	(899,496		)	(295,263		)
Net decrease in cash, cash equivalents and restricted cash and cash equivalents	$	(16,589	)	$	(105,484	)	$	(186,971	)

Cash provided by operating activities in the year ended December 31, 2017, was primarily affected by higher funds flow from operations (see funds flow from operations reconciliation under the heading “Consolidated Results of Operations” above) and a $29.2 million change in assets and liabilities from operating activities.

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes and costs related to operations and debt service also impact cash flow. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes, the impact of which we partially mitigate by entering into foreign currency derivatives.

Off-Balance Sheet Arrangements

As at December 31, 2017 and 2016, we had no off-balance sheet arrangements.

Contractual Obligations

The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancelable terms in excess of one year as of December 31, 2017:



	Total		2018		2019-2020		2021-2022		2022 and beyond
(Thousands of U.S. Dollars)
Revolving credit facility	$	148,000	$	—	$	148,000	$	—	$	—
5% Convertible Senior Notes due 2021	115,000		—		—		115,000		—
Total long-term debt	263,000		—		148,000		115,000		—
Interest payments⁽¹⁾	34,116		11,144		21,534		1,438		—
Oil transportation services	10,895		3,842		7,053		—		—
Facility construction	27,006		5,446		10,907		10,653		—
Operating leases	4,554		1,840		2,507		207		—
Software and telecommunication	961		339		622		—		—
Total	$	340,532	$	22,611	$	190,623	$	127,298	$	—

⁽¹⁾Interest payments have been calculated utilizing the rates associated with our Convertible Notes outstanding at December 31, 2017. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2017, outstanding balance of $148.0 million will be outstanding through the November 2020 maturity date and that our Convertible Notes will remain outstanding through their April 2021 maturity date. A constant interest rate of 3.64% was assumed for the interest payments on our revolving credit facility, which was the December 31, 2017 weighted-average interest rate. Actual results will differ from these estimates and assumptions.

During the year ended December 31, 2017, we borrowed a net amount of $57.0 million on our revolving credit facility. Additionally, during the year ended December 31, 2017, we sold our Peru and Brazil business units and their related obligations.

At December 31, 2017, we had provided promissory notes totaling $76.0 million to support letters of credit or surety bonds relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements. These unsecured letters of credit do not utilize our revolving credit facility capacity because they are backed by local Colombian banks or insurance companies.

The above table does not reflect estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties and other long-term liabilities, as we cannot determine with accuracy the timing of such payments. Information regarding our asset retirement obligation can be found in Note 8 to the Consolidated Financial Statements, Asset Retirement Obligation, in Item 8. “Financial Statements and Supplementary Data”.

The above table also excludes assets and liabilities associated with our derivative contracts, which are dependent on commodity prices or foreign exchange rates at the time of the contract settlement. Information regarding our derivatives can be found in Note 12 to the Consolidated Financial Statements, Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk, in Item 8. “Financial Statements and Supplementary Data”.

As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost and associated penalties may be payable.

Critical Accounting Policies and Estimates

The preparation of financial statements under GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as well as the revenues and expenses reported and disclosure of contingent liabilities. Changes in these estimates related to judgments and assumptions will occur as a result of changes in facts and circumstances or discovery of new information, and, accordingly, actual results could differ from amounts estimated.

On a regular basis we evaluate our estimates, judgments and assumptions. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material. The areas of accounting and the associated critical estimates and assumptions made are discussed below.

Full Cost Method of Accounting, Proved Reserves, DD&A and Impairment of Oil and Gas Properties

We follow the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note 2 to the Consolidated Financial Statements, Significant Accounting Policies, in Item 8. “Financial Statements and Supplementary Data”. Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of properties are capitalized, including internal costs directly attributable to these activities. The sum of net capitalized costs, including estimated asset retirement obligations ("ARO"), and estimated future development costs to be incurred in developing proved reserves are depleted using the unit-of-production method.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation. The ceiling test limits pooled costs to the aggregate of the discounted estimated after-tax future net revenues from proved oil and gas properties, plus the lower of cost or estimated fair value of unproved properties less any associated tax effects.

If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Any such write-down will reduce earnings in the period of occurrence and result in lower DD&A expenses in future periods. The ceiling limitation is imposed separately for each country in which we have oil and gas properties. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

Our estimates of proved oil and gas reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the amount and timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.

We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are evaluated at least annually by independent qualified reserves consultants.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that a 10% discount factor be used and future net revenues are calculated using prices that represent the average of the first day of each month price for the 12-month period. Therefore, the future net revenues associated with the

estimated proved reserves are not based on our assessment of future prices or costs, but reflect adjustments for gravity, quality, local conditions, gathering and transportation fees and distance from market. Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2017, ceiling tests were based on wellhead prices per BOE as of the first day of each month within that twelve month period of $43.00 for Colombia.

Because the ceiling test calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. Historical oil and gas prices for any particular 12-month period can be either higher or lower than our price forecast. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Our Reserves Committee oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence.

In the year ended December 31, 2017, we had no ceiling test impairment losses in our Colombia and Brazil cost centers. We used an average Brent price of $54.19 per bbl for the purposes of the December 31, 2017 ceiling test calculations (September 30, 2017 - 52.70, June 30, 2017 - $51.35, March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48, March 31, 2016 - $48.79; December 31, 2015 - $54.08).

In the year ended December 31, 2016, we recorded ceiling test impairment losses of $513.7 million in our Colombia cost center, and $71.1 million in our Brazil cost center. The Colombia ceiling test impairment loss related to lower oil prices and the fact that the acquisitions of PetroLatina and PetroAmerica were initially added into the cost base at estimated fair value. However, these acquired assets were subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which, uses constant commodity pricing that averages prices during the preceding 12 months. The Brazil ceiling test impairment loss related to continued low oil prices and increased costs in the depletable base as a result of a $45.0 million impairment of unproved properties. In the year ended December 31, 2015, we recorded ceiling test impairment losses of $232.4 million in our Colombia cost center, and $46.9 million in our Brazil cost center as a result of lower realized prices.

It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed U.S. GAAP ceiling test calculation. These factors include, but are not limited to, future commodity pricing, royalty rates in different pricing environments, operating costs and negotiated savings, foreign exchange rates, capital expenditures timing and negotiated savings, production and its impact on depletion and cost base, upward or downward reserve revisions as a result of ongoing exploration and development activity, and tax attributes.

Subject to these factors and inherent limitations and holding all factors constant other than benchmark oil prices, we do not believe that ceiling test impairment losses will be experienced in the first quarter of 2018. The calculation of the impact of higher commodity prices on our estimated ceiling test calculation was prepared based on the presumption that all other inputs and assumptions are held constant with the exception of benchmark oil prices. Therefore, this calculation strictly isolates the impact of commodity prices on the prescribed GAAP ceiling test. This calculation was based on pro forma Brent oil price of $57.74 per bbl for the 12 months ended March 31, 2018. This pro forma oil price was calculated using a 12-month unweighted arithmetic average of oil prices, and included the oil prices on the first day of the month for the eleven months ended February 2018, and, for the month ended March 2018, estimated oil prices for the first quarter of 2018 using the forward price curve forecast from Bloomberg dated December 31, 2017. As noted above, actual cash flows may be materially affected by other factors. For example, in Colombia, cash royalties are levied at lower rates in low oil price environments and foreign exchange rates can materially impact the deferred tax component of the asset base, operating costs, and the income tax calculation.

Holding all factors constant other than benchmark oil prices and related royalty rates, we do not expect any downward adjustment to our consolidated NAR reserve volumes during the first quarter of 2018. This disclosure is based on a pro forma Brent oil price of $57.74 per bbl for the 12 months ended March 31, 2018, calculated as described above.

Unproved properties

Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is

determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. Unproved properties, the costs of which are individually significant, are assessed individually by considering seismic data, plans or requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans and political, economic and market conditions. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, seismic evaluations, the assignment of proved reserves, availability of capital and other factors. For countries where a reserve base has not yet been established, the impairment is charged to earnings.

Asset Retirement Obligations

We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate.

We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, inflation factors, credit-adjusted risk-free discount rates and changes in legal, regulatory, environmental and political environments. Because costs typically extend many years into the future, estimating future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.

It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results.

Equity Method Investment

As described in Note 5 to the Consolidated Financial Statements, Property, Plant and Equipment, in Item 8. “Financial Statements and Supplementary Data”, during December 2017, we acquired an investment in common shares of Sterling in connection with the sale of our Peru business unit. At December 31, 2017, this investment represented approximately 46% of Sterling's issued and outstanding common shares. We determined that we did not have a controlling financial interest in Sterling, but could exert significant influence over Sterling's operating and financial policies as a result of our ownership interest in Sterling and the right to nominate two directors to Sterling's board of directors. Accordingly, we accounted for our investment in the common shares of Sterling as an equity method investment, but elected the fair value option for this investment.

The fair value of the current portion of the investment was estimated using quoted market prices in active markets. The long-term portion of the investment was estimated based on quoted market prices and valuation technique using observable and one or more unobservable inputs. Information regarding the valuation of the investment can be found in Note 12 to the Consolidated Financial Statements, Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk in Item 8. “Financial Statements and Supplementary Data”, which information is incorporated by reference here.

Goodwill

Goodwill represents the excess of the aggregate of the consideration transferred over net identifiable assets acquired and liabilities assumed. The goodwill on our balance sheet relates entirely to ourColombia reporting unit.

At each reporting date, we assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount and whether it is necessary to perform the goodwill impairment test. Changes in our future cash flows, operating results, growth rates, capital expenditures, cost of capital, discount rates, stock price or related market capitalization, could affect the results of our annual goodwill assessment and, accordingly, potentially lead to future goodwill impairment charges. The goodwill impairment test would require a comparison of the fair value of the reporting unit to its net book value If the estimated fair value of the reporting unit were less than its net book value, including goodwill, we would recognize the goodwill impairment in an amount not exceeding the carrying amount of goodwill through a charge to expense.

The most significant judgments involved in estimating the fair value of our reporting unit would relate to the valuation of our property and equipment. Unfavorable changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

At December 31, 2017, we performed a qualitative assessment of goodwill and, based on this assessment, no impairment of goodwill was identified. Forward curve oil prices as at December 31, 2017, were higher than those used in the ceiling test impairment calculation. Increased reserves and forward curve oil prices as at December 31, 2017, resulted in no impairment of goodwill.

Income Taxes

We follow the liability method of accounting for income taxes whereby we recognize deferred income tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.

To assess the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

Our effective tax rate is based on pre-tax income and the tax rates applicable to that income in the various jurisdictions in which we operate. An estimated effective tax rate for the year is applied to our quarterly operating results. In the event that there is a significant unusual or discrete item recognized, or expected to be recognized, in our quarterly operating results, the tax attributable to that item would be separately calculated and recorded at the same time as the unusual or discrete item. We consider the resolution of prior-year tax matters to be such items. Significant judgment is required in determining our effective tax rate and in evaluating our tax positions. We establish reserves when it is more likely than not that we will not realize the full tax benefit of the position. We adjust these reserves in light of changing facts and circumstances.

We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts.

Legal and Other Contingencies

A provision for legal and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal and other contingencies and periodically determines when we should record losses for these items based on information available to us.

Stock-Based Compensation

Our stock-based compensation cost is measured based on the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes-Merton simulation stock option-pricing model and/or observable share prices. These estimates depend on certain assumptions, including volatility, risk-free interest rate, the term of the awards, the forfeiture rate and performance factors, which, by their nature, are subject to measurement uncertainty. We use historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of our shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.

New Accounting Pronouncements

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date". The ASU deferred the effective date of the new revenue recognition model by one year. As a result, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" which clarifies implementation guidance on principal versus agent considerations. In April, May and December 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing", ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients" and ASU 2016-20 "Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers", respectively, which addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings.

We completed our evaluation of the impact of these ASUs and reviewed our various revenue streams and underlying contracts. We adopted the new standard using the modified retrospective method at the date of adoption, January 1, 2018. Adoption of the ASU did not have a material impact on our consolidated financial statements, other than enhanced disclosure related to revenues from contracts with customers.

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 on our consolidated financial position, results of operations or cash flows or disclosure.

In February 2016, the FASB issued ASU 2016-02, “Leases". This ASU will require most lease assets and lease liabilities to be

recognized on the balance sheet and the disclosure of key information about lease arrangements. The ASU will be effective for

fiscal years, and interim periods within those years, beginning after December 15, 2018. We are currently assessing the impact the new lease standard will have on our consolidated financial position, results of operations, cash flows, and disclosure.

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the current incurred

loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of

reasonable and supportable information to support credit loss estimates. The ASU will be effective for fiscal years, and interim

periods within those years, beginning after December 15, 2019. We are currently assessing the impact this update will have on our consolidated financial position, results of operations, cash flows, and disclosure.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity price 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. 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.

During the year ended December 31, 2017, we entered into commodity price derivative contracts to manage the variability cash flows associated with the forecasted sale of our oil production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending. The table below provides information about

our commodity price derivative contracts at December 31, 2017, including the notional amounts and weighted average exchange rates by expected (contractual) maturity dates. Expected cash flows from the forward contract equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. We do not hold any of these investments for trading purposes.



Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: January 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: January 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

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. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI 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. 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 $10,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar.

During the year ended December 31, 2017, we entered into foreign currency derivative contracts to manage the variability in cash flows associated with our forecasted Colombian peso denominated costs. The table below provides information about our foreign currency forward exchange agreements at December 31, 2017, including the notional amounts and weighted average exchange rates by expected (contractual) maturity dates. Expected cash flows from the forward contract equaled the fair value of the contract. The information is presented in U.S. dollars because that is our reporting currency. We do not hold any of these investments for trading purposes.



Period and type of instrument	Amount hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: January 1, 2018 to December 31, 2018	174,000	58,311	COP	3,000	3,107

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our revolving credit facility, which bears floating rates of interest. At December 31, 2017, our outstanding revolving credit facility was $148.0 million (December 31, 2016 - $90.0 million), which had a weighted-average interest rate of approximately 3.64%. A 10% change in LIBOR would not materially impact our interest expense on debt outstanding at December 31, 2017.

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.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Gran Tierra Energy Inc. and subsidiaries (the "Company") as at December 31, 2017 and 2016, the related consolidated statements of operations, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)(PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on 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, 2018 expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. Further, we are required to be independent of the Company in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada and to fulfill our other ethical responsibilities in accordance with these requirements.

We conducted our audits in accordance with the standards of the PCAOB and Canadian generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte LLP

Chartered Professional Accountants

Calgary, Canada

February 27, 2018

We have served as the Company's auditor since 2005

Gran Tierra Energy Inc.

Consolidated Statements of Operations

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



	Year Ended December 31,
	2017			2016			2015
OIL AND NATURAL GAS SALES (NOTE 3)	$	421,734		$	289,269		$	276,011

EXPENSES
Operating	109,869			86,925			75,565
Transportation	25,107			31,776			40,204
Depletion, depreciation and accretion (Note 3)	131,335			139,535			176,386
Asset impairment (Notes 3 and 5)	1,514			616,649			323,918
General and administrative (Note 3)	39,014			33,218			32,353
Severance	1,287			1,319			8,990
Transaction	—			7,325			—
Equity tax (Note 9)	1,224			3,098			3,769
Foreign exchange loss (gain)	2,067			(1,469		)	(17,242		)
Financial instruments loss (Note 12)	15,929			10,279			2,027
Other gain	—			—			(502		)
Interest expense (Notes 3 and 6)	13,882			14,145			—
	341,228			942,800			645,468

(LOSS) ON SALE OF BUSINESS UNITS (NOTE 3 and 5) AND GAIN ON ACQUISITION	(44,385		)	929			—
INTEREST INCOME	1,209			2,368			1,369
INCOME (LOSS) BEFORE INCOME TAXES (NOTE 3)	37,330			(650,234		)	(368,088		)

INCOME TAX EXPENSE (RECOVERY)
Current (Note 9)	24,322			20,122			15,383
Deferred (Note 9)	44,716			(204,791		)	(115,442		)
	69,038			(184,669		)	(100,059		)
NET LOSS AND COMPREHENSIVE LOSS	$	(31,708	)	$	(465,565	)	$	(268,029	)

NET LOSS PER SHARE - BASIC AND DILUTED	$	(0.08	)	$	(1.45	)	$	(0.94	)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC AND DILUTED (Note 7)	396,683,593			320,851,538			285,333,869

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Consolidated Balance Sheets

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



	As at December 31,
	2017			2016
ASSETS
Current Assets
Cash and cash equivalents (Note 13)	$	12,326		$	25,175
Restricted cash and cash equivalents (Notes 8 and 13)	11,787			8,322
Accounts receivable (Note 4)	45,353			45,698
Investment (Note 12)	25,055			—
Derivatives (Note 12)	302			578
Inventory	7,075			7,766
Taxes receivable	40,831			26,393
Prepaid taxes (Notes 2 and 9)	—			12,271
Other prepaids	2,516			5,482
Total Current Assets	145,245			131,685

Oil and Gas Properties (using the full cost method of accounting)
Proved	629,081			412,319
Unproved	464,948			647,774
Total Oil and Gas Properties	1,094,029			1,060,093
Other capital assets	5,195			6,516
Total Property, Plant and Equipment (Notes 3 and 5)	1,099,224			1,066,609

Other Long-Term Assets
Deferred tax assets (Note 2 and 9)	57,310			1,611
Prepaid taxes (Notes 2 and 9)	—			41,784
Investment (Note 12)	19,147			—
Other long-term assets (Note 13)	6,112			23,626
Goodwill (Note 3)	102,581			102,581
Total Other Long-Term Assets	185,150			169,602
Total Assets (Note 3)	$	1,429,619		$	1,367,896

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities (Note 10)	$	126,171		$	107,051
Derivatives (Note 12)	21,151			3,824
Taxes payable (Note 9)	9,324			38,939
Asset retirement obligation (Note 8)	323			5,215
Total Current Liabilities	156,969			155,029

Long-Term Liabilities
Long-term debt (Notes 6 and 12)	256,542			197,083
Deferred tax liabilities (Note 2 and 9)	28,417			107,230
Asset retirement obligation (Note 8)	31,241			38,142
Other long-term liabilities	20,115			11,425
Total Long-Term Liabilities	336,315			353,880

Commitments and Contingencies (Note 11)
Subsequent Event (Note 14)
Shareholders’ Equity
Common Stock (Note 7) (385,191,042 and 390,807,194 shares of Common Stock and 6,111,665 and 8,199,894 exchangeable shares, par value $0.001 per share, issued and outstanding as at December 31, 2017 and December 31, 2016, respectively)	10,295			10,303
Additional paid in capital	1,327,244			1,342,656
Deficit	(401,204		)	(493,972		)
Total Shareholders’ Equity	936,335			858,987
Total Liabilities and Shareholders’ Equity	$	1,429,619		$	1,367,896

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Consolidated Statements of Cash Flows

(Thousands of U.S. Dollars)



	Year Ended December 31,
	2017			2016			2015
Operating Activities
Net loss	$	(31,708	)	$	(465,565	)	$	(268,029	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 3)	131,335			139,535			176,386
Asset impairment (Notes 3 and 5)	1,514			616,649			323,918
Deferred tax expense (recovery) (Note 9)	44,716			(204,791		)	(115,442		)
Stock-based compensation (Note 7)	9,775			6,339			2,733
Amortization of debt issuance costs (Note 6)	2,415			5,691			—
Cash settlement of restricted share units	(564		)	(1,234		)	(1,392		)
Unrealized foreign exchange loss (gain)	837			(1,428		)	(8,380		)
Financial instruments loss (Note 12)	15,929			10,279			2,027
Cash settlement of financial instruments	1,563			438			(3,749		)
Cash settlement of asset retirement obligation (Note 8)	(1,336		)	(605		)	(6,217		)
Loss on sale of business units (Note 3 and 5) and (gain) on acquisition	44,385			(929		)	—
Other gain	—			—			(502		)
Net change in assets and liabilities from operating activities (Note 13)	(29,217		)	(11,337		)	(39,048		)
Net cash provided by operating activities	189,644			93,042			62,305

Investing Activities
Additions to property, plant and equipment (Note 3)	(251,041		)	(127,789		)	(156,639		)
Property acquisitions (Note 5)	(34,410		)	(19,388		)	—
Net proceeds from sale of business units (Note 5)	32,968			—			—
Cash paid for investments (Note 5)	(11,000		)	—			—
Cash paid for business combinations, net of cash acquired	—			(488,196		)	—
Proceeds from the sale of oil and gas properties (Note 5)	—			6,000			—
Proceeds from sale of marketable securities (Note 12)	—			2,325			—
Changes in non-cash investing working capital	19,680			21,116			(76,844		)
Net cash used in investing activities	(243,803		)	(605,932		)	(233,483		)

Financing Activities
Proceeds from bank debt, net of issuance costs	167,043			256,065			—
Repayment of bank debt	(110,000		)	(252,181		)	—
Repurchase of shares of Common Stock (Note 7)	(17,916		)	—			(9,999		)
Proceeds from issuance of shares of Common Stock, net of issuance costs	—			128,273			722
Proceeds from issuance of subscription receipts, net of issuance costs	—			165,805			—
Proceeds from issuance of Convertible Notes, net of issuance costs	—			109,090			—
Net cash provided by (used in) financing activities	39,127			407,052			(9,277		)

Foreign exchange (loss) gain on cash, cash equivalents and restricted cash and cash equivalents	(1,557		)	354			(6,516		)

Net decrease in cash, cash equivalents and restricted cash and cash equivalents	(16,589		)	(105,484		)	(186,971		)
Cash, cash equivalents and restricted cash and cash equivalents, beginning of year (Note 13)	43,267			148,751			335,722
Cash, cash equivalents and restricted cash and cash equivalents, end of year (Note 13)	$	26,678		$	43,267		$	148,751

Supplemental cash flow disclosures (Note 13)

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Consolidated Statements of Shareholders’ Equity

(Thousands of U.S. Dollars)



	Year Ended December 31,
	2017			2016			2015
Share Capital
Balance, beginning of year	$	10,303		$	10,186		$	10,190
Issuance of Common Stock (Note 7)	—			117			—
Repurchase of Common Stock (Note 7)	(8		)	—			(4		)
Balance, end of year	10,295			10,303			10,186

Additional Paid in Capital
Balance, beginning of year	1,342,656			1,019,863			1,026,873
Issuance of Common Stock, net of share issuance costs (Note 7)	—			314,425			—
Exercise of stock options (Note 7)	—			5,347			722
Stock-based compensation (Note 7)	2,496			3,021			2,263
Repurchase of Common Stock (Note 7)	(17,908		)	—			(9,995		)
Balance, end of year	1,327,244			1,342,656			1,019,863

(Deficit) Retained Earnings
Balance, beginning of year	(493,972		)	(28,407		)	239,622
Net loss	(31,708		)	(465,565		)	(268,029		)
Cumulative adjustment for accounting changes related to tax reorganizations (Note 2)	124,476			—			—
Balance, end of year	(401,204		)	(493,972		)	(28,407		)

Total Shareholders’ Equity	$	936,335		$	858,987		$	1,001,642

(See notes to the consolidated financial statements)

Gran Tierra Energy Inc.

Notes to the Consolidated Financial Statements

For the Years Ended December 31, 2017, 2016 and 2015

(Expressed in U.S. Dollars, unless otherwise indicated)

1. Description of Business

Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production in Colombia. The Company also had business activities in Brazil until June 30, 2017, and in Peru until December 18, 2017.

2. Significant Accounting Policies

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

Significant accounting policies are:

Basis of consolidation

These consolidated financial statements include the accounts of the Company and its controlled subsidiaries. All intercompany accounts and transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows; depreciation, depletion, amortization and impairment (“DD&A”); impairment assessments of goodwill; timing of transfers from oil and gas properties not subject to depletion to the depletable base; asset retirement obligations; determining the value of the consideration transferred and the net identifiable assets acquired and liabilities assumed in connection with business combinations and determining goodwill; assessments of the likely outcome of legal and other contingencies; income taxes; stock-based compensation; and determining the fair value of derivatives and investment. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates.

Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted cash and cash equivalents

Restricted cash and cash equivalents comprises cash and cash equivalents pledged to secure letters of credit and to settle asset retirement obligations. Letters of credit currently secured by cash relate to work commitment guarantees contained in exploration contracts. Restrictions will lapse when work obligations are satisfied pursuant to the exploration contract or an asset retirement obligation is settled. Cash and claims to cash that are restricted as to withdrawal or use for other than current operations or are designated for expenditure in the acquisition or construction of long-term assets are excluded from the current asset classification. The long term portion of restricted cash and cash equivalents is included in other long-term assets on the Company's balance sheet.

Allowance for doubtful accounts

The Company estimates losses on receivables based on known uncollectible accounts, if any, and historical experience of losses incurred and accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. The allowance for doubtful receivables was nil at December 31, 2017 and 2016.

Equity method investment

During December 2017, the Company acquired an investment in common shares of Sterling in connection with the sale of its Peru business unit (Note 5). At December 31, 2017, this investment represented approximately 46% of Sterling's issued and outstanding common shares. The Company determined that it did not have a controlling financial interest in Sterling, but could exert significant influence over Sterling's operating and financial policies as a result of its ownership interest in Sterling and the right to nominate two directors to Sterling's board of directors. Accordingly, Gran Tierra accounted for its investment in the common shares of Sterling as an equity method investment, but elected the fair value option for this investment to reflect the value that market participants would use to value the investment. The fair value of the investment in Sterling's common shares is recorded in 'Investments' in the consolidated balance sheet, and the change in fair value is recorded in the consolidated statement of operations as financial instruments gains or losses.

Derivatives

The Company records derivative instruments on its balance sheet at fair value as either an asset or liability with changes in fair value recognized in the consolidated statements of operations as financial instruments gains or losses. While the Company utilizes derivative instruments to manage the price risk attributable to its expected oil production and foreign exchange risk, it has elected not to designate its derivative instruments as accounting hedges under the accounting guidance.

Inventory

Inventory consists of oil in tanks and third party pipelines and supplies and is valued at the lower of cost and net realizable value. The cost of inventory is determined using the weighted average method. Oil inventories include expenditures incurred to produce, upgrade and transport the product to the storage facilities and include operating, depletion and depreciation expenses and cash royalties.

Income taxes

Income taxes are recognized using the liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax base, and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. Valuation allowances are provided if, after considering available evidence, it is not more likely than not that some or all of the deferred tax assets will be realized.

The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The Company recognizes potential penalties and interest related to unrecognized tax benefits as a component of income tax expense.

Oil and gas properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties as defined by the Securities and Exchange Commission (“SEC”). Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Costs associated with production and general corporate activities; however, are expensed as incurred. Separate cost centers are maintained for each country in which the Company incurs costs.

The Company computes depletion of oil and natural gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Future development costs related to properties with proved reserves are also included in the amortization base for computation of depletion. The costs of unproved properties are excluded from the amortization base until the properties are evaluated. The cost of exploratory dry wells is transferred to proved properties, and thus is subject to amortization, immediately upon determination that a well is dry in those countries where proved reserves exist.

The Company performs a ceiling test calculation each quarter in accordance with SEC Regulation S-X Rule 4-10. In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and

natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to net income or loss. Any such write-down will reduce earnings in the period of occurrence and results in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

The Company calculates future net cash flows by applying the unweighted average of prices in effect on the first day of the month for the preceding 12-month period, adjusted for location and quality differentials. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts.

Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the depletable base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. This evaluation considers, among other factors, seismic data, requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to depletion. For countries where a reserve base has not yet been established, the impairment is charged to earnings.

In exploration areas, related seismic costs are capitalized in unproved property and evaluated as part of the total capitalized costs associated with a property. Seismic costs related to development projects are recorded in proved properties and therefore subject to depletion as incurred.

Gains and losses on the sale or other disposition of oil and natural gas properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

Asset retirement obligation

The Company records an estimated liability for future costs associated with the abandonment of its oil and gas properties including the costs of reclamation of drilling sites. The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to the related oil and gas properties. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets. The accretion of the asset retirement obligation and amortization of the asset retirement cost are included in DD&A. If estimated future costs of an asset retirement obligation change, an adjustment is recorded to both the asset retirement obligation and oil and gas properties. Revisions to the estimated asset retirement obligation can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Other capital assets

Other capital assets, including additions and replacements, are recorded at cost upon acquisition and include furniture, fixtures and leasehold improvement, computer equipment and automobiles. Depreciation is provided using the declining-balance method at a 30% annual rate for furniture and fixtures, computer equipment and automobiles. Leasehold improvements are depreciated on a straight-line basis over the shorter of the estimated useful life and the term of the related lease. The cost of repairs and maintenance is charged to expense as incurred.

Goodwill

Goodwill represents the excess of the aggregate of the consideration transferred over the net identifiable assets acquired and liabilities assumed. The Company assesses qualitative factors annually, or more frequently if necessary, to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether it is necessary to perform the goodwill impairment test. The impairment test requires allocating goodwill and certain other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared with its net book value. An impairment loss is recognized if the estimated fair value of the reporting unit is less than its carrying amount, not exceeding the carrying amount of goodwill allocated to that reporting unit. Because quoted market prices are not available for the Company’s

reporting unit, the fair value of the reporting unit is estimated based upon estimated future cash flows of the reporting unit. The goodwill relates entirely to the Colombia reportable segment. The Company performed a qualitative assessment of goodwill at December 31, 2017, and based on this assessment, no impairment of goodwill was identified.

Convertible Notes

The Company accounts for its 5.00% Convertible Senior Notes due 2021 (the "Convertible Notes") as a liability in their entirety. The embedded features of the Convertible Notes were assessed for bifurcation from the Convertible Notes under the applicable provisions, including the basic conversion feature, the fundamental change make-whole provision and the put and call options. Based on an assessment, the Company concluded that these embedded features did not meet the criteria to be accounted for separately.

The Company incurred debt issuance costs in connection with the issuance of the Convertible Notes which have been presented as a direct deduction against the carrying amount of the Convertible Notes and are being amortized to interest expense using the effective interest method over the contractual term of the Convertible Notes.

Revenue recognition

Revenue from the production of oil and natural gas is recognized when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable, the sale is evidenced by a contract and collection of the revenue is reasonably assured.

Revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.

Stock-based compensation

The Company records stock-based compensation expense in its consolidated financial statements measured at the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes-Merton or Monte Carlo simulation stock option-pricing models and/or observable share prices. For equity-settled stock-based compensation awards, fair values are determined at the grant date and the expense, net of estimated forfeitures, is recognized using the accelerated method over the requisite service period. An adjustment is made to compensation expense for any difference between the estimated forfeitures and the actual forfeitures. For cash-settled stock-based compensation awards, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities.

The Company uses historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of the Company’s shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.

Stock-based compensation expense is capitalized as part of oil and natural gas properties or expensed as part of general and administrative (“G&A”) or operating expenses, as appropriate.

Foreign currency translation

The functional currency of the Company, including its subsidiaries, is the United States dollar. Monetary items are translated into the reporting currency at the exchange rate in effect at the balance sheet date and non-monetary items are translated at historical exchange rates. Revenue and expense items are translated in a manner that produces substantially the same reporting currency amounts that would have resulted had the underlying transactions been translated on the dates they occurred.

DD&A expense on assets is translated at the historical exchange rates similar to the assets to which they relate. Gains and losses resulting from foreign currency transactions, which are transactions denominated in a currency other than the entity’s functional currency, are recognized in net income or loss.

Loss per share

Basic loss per share is calculated by dividing loss attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income or loss per

share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading price of shares of Common Stock during the period.

Recently Adopted Accounting Pronouncements

Simplifying the Measurement of Inventory

In July 2015, the Financial Accounting Standards Board (“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 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The implementation of this update did not have an impact on the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Employee Share-Based Payment Accounting

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting". This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company elected to continue to estimate the total number of awards for which the requisite service period will not be rendered. The implementation of this update did not impact the Company’s consolidated financial position, results of operations or cash flows or disclosure.

Income Taxes - Intra-Entity Transfers of Assets Other than Inventory

At December 31, 2016, GAAP prohibited the recognition of current and deferred income taxes for intra-entity transfers until an asset leaves the consolidated group, therefore, the current income tax effect of tax reorganizations completed in 2016 was deferred and recognized as prepaid income taxes. At December 31, 2016, the Company's balance sheet included $54.1 million of prepaid income taxes, $12.3 million in current prepaid taxes and $41.8 million in long-term prepaid taxes, and $37.5 million of current income taxes payable relating to tax reorganizations completed in 2016.

In October 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other than Inventory." This ASU requires companies to recognize the income tax effects of intercompany sales or transfers of assets, other than inventory, in the income statement as income tax expense or benefit in the period the sale or transfer occurs. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption was permitted as of the beginning of an annual reporting period. The ASU is required to be applied on a modified retrospective basis with a cumulative-effect adjustment directly to retained earnings in the period of adoption. The Company early adopted this ASU on January 1, 2017, and in the three months ending March 31, 2017, wrote off the income tax effects that had been deferred from past intercompany transactions to opening deficit. A total of $124.5 million, representing deferred tax assets of $178.6 million, net of $54.1 million of prepaid tax, was recorded directly to opening deficit at January 1, 2017. Deferred tax assets recorded upon adoption were assessed for realizability under Accounting Standards Codification ("ASC") 740 "Income Taxes", and, valuation allowances were recognized on those deferred tax assets as necessary on the date of adoption. The adoption of ASU 2016-16 did not have any effect on the Company’s cash flows.

Restricted Cash and Cash Equivalents

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash". ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted. The Company early adopted this ASU on January 1, 2017, on a retrospective basis to each period presented. The implementation of this ASU did not impact the Company's consolidated financial position or results of operations. For the year ended December 31, 2016, the net decrease in cash, cash equivalents and restricted cash and cash equivalents currently disclosed was $105.5 million, compared with the net decrease in cash and cash equivalents of $120.2 million as previously disclosed in the consolidated statement of cash flows

prior to the adoption of ASU 2016-18. For the year ended December 31, 2015, the net decrease in cash, cash equivalents and restricted cash and cash equivalents currently disclosed was $187.0 million, compared with the net decrease in cash and cash equivalents of $186.5 million as previously disclosed in the consolidated statement of cash flows prior to the adoption of ASU 2016-18.

Clarifying the Definition of a Business

In January 2017, the FASB issued ASU 2017-01, "Clarifying the Definition of a Business". ASU 2017-01 narrows the definition of a business and provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. ASU 2017-01 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted and the Company adopted this ASU on January 1, 2017. The Company now applies an initial screen for determining whether a transaction involves an asset or a business. When substantially all of the fair value of the gross assets acquired is concentrated in a single identified asset, or group of similar identifiable assets, the set will not be a business and no goodwill or gain on acquisition will be recognized. If the screen is not met, a set cannot be considered a business unless it includes an input and a substantive process that together significantly contribute to the ability to create an output. The Company’s acquisition of the Santana and Nancy Burdine-Maxine oil and gas properties during the year ended December 31, 2017 was not considered a business under this ASU and therefore not allocated goodwill or gain on acquisition (Note 5).

Simplifying the Test for Goodwill Impairment

In January 2017, the FASB issued ASU 2017-04, "Simplifying the Test for Goodwill Impairment". ASU 2017-04 eliminates step 2 of the goodwill impairment test. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU 2017-04 is effective for annual reporting periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2019. Early adoption is permitted. At December 31, 2017, the Company performed a qualitative assessment of goodwill and, based on this assessment, no impairment of goodwill was identified.

Recently Issued Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral of the Effective Date”. The ASU deferred the effective date of the new revenue recognition model by one year. As a result, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance on principal versus agent considerations. In April, May and December 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients” and ASU 2016-20 “Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers”, respectively, which addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings.

The Company has completed its evaluation of the impact of the ASU and has reviewed its various revenue streams and underlying contracts. The Company adopted the new standard using the modified retrospective method at the date of adoption, January 1, 2018. Adoption of the ASU did not have a material impact on the Company’s consolidated financial statements, other than enhanced disclosure related to revenues from contracts with customers as prescribed by ASU.

Recognition and Measurement of Financial Assets and Financial Liabilities

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 on the Company's consolidated financial position, results of operations or cash flows or disclosure.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases". This ASU will require most lease assets and lease liabilities to be

recognized on the balance sheet and the disclosure of key information about lease arrangements. The ASU will be effective for

fiscal years, and interim periods within those years, beginning after December 15, 2018. The Company is currently assessing

the impact the new lease standard will have on its consolidated financial position, results of operations, cash flows, and disclosure.

Financial Instruments - Credit Losses

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the current incurred

loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of

reasonable and supportable information to support credit loss estimates. The ASU will be effective for fiscal years, and interim

periods within those years, beginning after December 15, 2019. The Company is currently assessing the impact this update will

have on its consolidated financial position, results of operations, cash flows, and disclosure.

3. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil and natural gas. The Company has one reportable segment based on geographic organization, Colombia. Prior to the sale of the Company's Brazil business unit effective June 30, 2017 and its Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. The "All Other" category represents the Company’s corporate, Brazil and Peru activities until the date of sale. The Company evaluates reportable segment performance based on income or loss before income taxes.

The following tables present information on the Company’s reportable segment and other activities:



	Year Ended December 31, 2017
(Thousands of U.S. Dollars)	Colombia			All Other			Total
Oil and natural gas sales	$	413,316		$	8,418		$	421,734
DD&A expenses	126,453			4,882			131,335
Asset impairment	—			1,514			1,514
General and administrative expenses	23,500			15,514			39,014
Interest expense	486			13,396			13,882
Loss on sale	—			(44,385		)	(44,385		)
Income (loss) before income taxes	111,829			(74,499		)	37,330
Segment capital expenditures	242,636			8,405			251,041
	Year Ended December 31, 2016
(Thousands of U.S. Dollars)	Colombia			All Other			Total
Oil and natural gas sales	$	280,872		$	8,397		$	289,269
DD&A expenses	132,569			6,966			139,535
Asset impairment	514,314			102,335			616,649
General and administrative expenses	17,187			16,031			33,218
Interest expense	—			14,145			14,145
Gain on acquisition	—			929			929
Loss before income taxes	(505,447		)	(144,787		)	(650,234		)
Segment capital expenditures	105,963			21,826			127,789
	Year Ended December 31, 2015
(Thousands of U.S. Dollars)	Colombia			All Other			Total
Oil and natural gas sales	$	269,035		$	6,976		$	276,011
DD&A expenses	167,701			8,685			176,386
Asset impairment	235,069			88,849			323,918
General and administrative expenses	9,805			22,548			32,353
Loss before income taxes	(238,463		)	(129,625		)	(368,088		)
Segment capital expenditures	85,326			71,313			156,639



	As at December 31, 2017
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	1,096,833	$	2,391	$	1,099,224
Goodwill	102,581		—		$	102,581
All other assets	176,980		50,834		$	227,814
Total Assets	$	1,376,394	$	53,225	$	1,429,619

	As at December 31, 2016
(Thousands of U.S. Dollars)	Colombia		All Other		Total
Property, plant and equipment	$	939,947	$	126,662	$	1,066,609
Goodwill	102,581		—		$	102,581
All other assets	177,393		21,313		$	198,706
Total Assets	$	1,219,921	$	147,975	$	1,367,896

The following table presents the number of customers from whom the Company derived 10% or more of its consolidated oil and gas sales and sales as a percentage of the Company's consolidated oil and gas sales to each customer. All of these customers were in the Company's Colombian reportable segment:



	Year Ended December 31,
	2017						2016						2015
Number of significant customers	3						3						4
Sales to each significant customer as % of oil and gas sales	44	%	31	%	17	%	40	%	34	%	13	%	43	%	15	%	13	%	12	%

4. Accounts Receivable



	As at December 31,
(Thousands of U.S. Dollars)	2017		2016
Trade	$	37,794	$	39,203
Other	7,559		6,495
	$	45,353	$	45,698

5. Property, Plant and Equipment



	As at December 31,
(Thousands of U.S. Dollars)	2017			2016
Oil and natural gas properties
Proved	$	2,810,796		$	2,652,171
Unproved	464,948			647,774
	3,275,744			3,299,945
Other	26,401			29,445
	3,302,145			3,329,390
Accumulated depletion, depreciation and impairment	(2,202,921		)	(2,262,781		)
	$	1,099,224		$	1,066,609

Depletion and depreciation expense on property, plant and equipment for the year ended December 31, 2017, was $126.8 million (year ended December 31, 2016 - $130.2 million; year ended December 31, 2015 - $177.9 million). A portion of depletion and depreciation expense was recorded as inventory in each year and adjusted for inventory changes.

Asset impairment for the three years ended December 31, 2017, was as follows:



(Thousands of U.S. Dollars)	Year Ended December 31,
	2017		2016		2015
Impairment of oil and gas properties	$	1,514	$	615,985	$	321,285
Impairment of inventory	—		664		2,633
	$	1,514	$	616,649	$	323,918

In the year ended December 31, 2016, the Company recorded ceiling test impairment losses of $513.7 million in its Colombia cost center, and $71.1 million in its Brazil cost center. The Colombia ceiling test impairment loss related to lower oil prices and the fact that the acquisitions of PetroLatina and PetroAmerica were initially added into the cost base at estimated fair value. However, these acquired assets were subjected to a prescribed U.S. GAAP ceiling test, which is not a fair value test, and which, as noted below, uses constant commodity pricing that averages prices during the preceding 12 months. The Brazil ceiling test impairment loss related to continued low oil prices and increased costs in the depletable base as a result of a $45.0 million impairment of unproved properties.

In the year ended December 31, 2015, the Company recorded ceiling test impairment losses of $232.4 million in its Colombia cost center, and $46.9 million in its Brazil cost center as a result of lower realized prices.

The Company follows the full cost method of accounting for its oil and gas properties. 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. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, Gran Tierra used an average Brent price of $54.19 per bbl for the purposes of the December 31, 2017 ceiling test calculations (September 30, 2017 - 52.70, June 30, 2017 - $51.35, March 31, 2017 - $49.33; December 31, 2016 - $42.92; September 30, 2016 - $42.23; June 30, 2016 - $44.48, March 31, 2016 - $48.79; December 31, 2015 - $54.08).

In the years ended December 31, 2016 and 2015, the Company recorded impairment losses of $31.2 million and $41.9 million, respectively, related to costs incurred on Block 95 and other blocks in Peru. On February 19, 2015, the Company made the decision to cease all further development expenditures on the Bretaña Field on Block 95 other than what is necessary to maintain tangible asset integrity and security.

Acquisition of Santana and Nancy Burdine-Maxine Blocks

On April 27, 2017, the Company acquired the Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin for cash consideration of $30.4 million. The acquisition was accounted for as an asset acquisition with the consideration paid allocated on a relative fair value basis to the net assets acquired.

The following table shows the allocation of the cost of the acquisition based on the relative fair values of the assets and

liabilities acquired:



(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	30,410

Allocation of Consideration Paid:
Oil and gas properties
Proved	$	24,405
Unproved	8,649
	33,054
Inventory	869
Asset retirement obligation - long-term	(3,513		)
	$	30,410

Acquisition of PGC

On January 25, 2016, the Company acquired all of the issued and outstanding common shares of PGC, pursuant to the terms and conditions of an acquisition agreement dated January 14, 2016. Upon completion of the transaction, PGC became an indirect wholly-owned subsidiary of Gran Tierra. The net purchase price of PGC was $19.4 million, after giving consideration to net working capital of $18.3 million. The acquisition was accounted for as an asset acquisition with the excess consideration paid over the fair value of the net assets acquired allocated on a relative fair value basis to the net assets acquired.



(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	37,727

Allocation of Consideration Paid:
Oil and gas properties
Proved	$	12,228
Unproved	15,563
	27,791
Net working capital (including cash acquired of $0.2 million and restricted cash of $18.6 million)	18,339
Asset retirement obligation - long-term	(8,403		)
	$	37,727

Property acquisitions in the year ended December 31, 2017 included $4.0 million of contingent consideration related to the 2016 acquisition of PGC. The contingent consideration was subject to Gran Tierra reaching a certain level of production plus gross proved plus probable reserves in the Putumayo-7 Block and was payable at December 31, 2017. The Company recognized contingent consideration in accounts payable and accrued liabilities on its balance sheet as at December 31, 2017.

Disposition of Peru Business Unit

On December 18, 2017, Gran Tierra completed the sale of its Peru business unit. Pursuant to the divestiture, Sterling acquired all of the issued and outstanding shares in Gran Tierra's indirect, wholly owned subsidiary that indirectly held all of its Peruvian assets for aggregate consideration of $33.5 million, comprised of approximately 187.3 million common shares of Sterling and an estimated cash-settled working capital adjustment of $0.4 million. Escrow conditions are applicable to 90% of the share consideration, which will be released from escrow at 15% every 6 months for 36 months following December 18, 2017. Additionally, in connection with the divestiture, Gran Tierra purchased $11.0 million of subscription receipts which were exchangeable for common shares of PetroTal Ltd. and subsequently exchanged them for approximately 58.9 million common shares of Sterling. After giving effect to the divestiture, Gran Tierra directly and indirectly holds approximately 246.2 million common shares representing approximately 46% of Sterling's issued and outstanding common shares. Sterling is a junior oil and gas company focused on development of oil and gas assets in Peru.

In connection with the divestiture, Gran Tierra, through two of its indirect, wholly owned subsidiaries, entered into an investor rights agreement with Sterling, pursuant to which, Gran Tierra has the right to nominate two directors to the board of Sterling, as well as certain demand and piggy-back registration rights and certain pre-emptive rights, subject to the terms and conditions set forth in the investor rights agreement. Gran Tierra is prohibited from exercising voting rights over more than 30% of the issued and outstanding Sterling Common Shares. In addition, Gran Tierra, through its indirect, wholly-owned subsidiary, entered into a carried interest and option agreement with Sterling and a Peruvian subsidiary, pursuant to which Gran Tierra has a 20% carried working interest in Block 107, located in the Ucayali basin in Peru, which interest may, at the option of Gran Tierra, either be converted to a non-carried working interest or be forfeited following the drilling of an exploration well in Block 107.

At December 18, 2017, the net book value of the Peru business unit was greater than proceeds received resulting in a $34.1 million loss on sale.

At December 31, 2016, assets and liabilities of the Peru business unit were as follows:



(Thousands of U.S. Dollars)	As at December 31, 2016
Current assets	$	1,051
Property, plant and equipment	68,428
Other long-term assets	9,799
	$	79,278

Current liabilities	$	(940	)
Long-term liabilities	(13,370		)
	$	(14,310	)

Disposition of Brazil Business Unit

On June 30, 2017, the Company, through two of its indirect subsidiaries (the “Selling Subsidiaries”), completed the previously announced disposition of its assets in Brazil. Gran Tierra completed the disposition of its Brazil business unit for a purchase price of $35.0 million, which, after certain final closing adjustments, resulted in cash consideration paid to the Selling Subsidiaries of approximately $36.8 million.

At June 30, 2017, the net book value of the Brazil business unit was greater than proceeds received resulting in a $10.2 million loss on sale.

At December 31, 2016, assets and liabilities of the Brazil business unit were as follows:



(Thousands of U.S. Dollars)	As at December 31, 2016
Current assets	$	1,634
Property, plant and equipment	55,376
	$	57,010

Current liabilities	$	(11,590	)
Long-term liabilities	(2,297		)
	$	(13,887	)

Other

During the year ended December 31, 2016, Gran Tierra sold non-operated and non-core assets in Colombia to a third party for cash consideration of $6.0 million.

Unproved oil and natural gas properties

At December 31, 2017, unproved oil and natural gas properties consist of exploration lands held in Colombia. Unproved oil and natural gas properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration warrants whether or not future areas will be developed. The Company expects that approximately 76% of costs not subject to depletion at December 31, 2017, will be transferred to the depletable base within the next five years and the remainder in the next five to 10 years.

The following is a summary of Gran Tierra’s oil and natural gas properties not subject to depletion as at December 31, 2017:



	Costs Incurred in
(Thousands of U.S. Dollars)	2017		2016		2015		Prior to 2015		Total
Acquisition costs - Colombia	$	8,076	$	319,025	$	—	$	33,080	$	360,181
Exploration costs - Colombia	52,769		10,124		8,795		33,079		104,767
	$	60,845	$	329,149	$	8,795	$	66,159	$	464,948

6. Debt and Debt Issuance Costs

The Company's debt at December 31, 2017 and 2016, was as follows:



	As at December 31,
(Thousands of U.S. Dollars)	2017			2016
Convertible Notes (a)	$	115,000		$	115,000
Revolving credit facility (b)	148,000			90,000
Unamortized debt issuance costs	(6,458		)	(7,917		)
Long-term debt	$	256,542		$	197,083

a) Convertible Notes

At December 31, 2017, the Company had $115 million of Convertible Notes outstanding. The Convertible Notes bear interest at a rate of 5.00% per year, payable semi-annually in arrears on April 1 and October 1 of each year, beginning on October 1, 2016. The Convertible Notes will mature on April 1, 2021, unless earlier redeemed, repurchased or converted. The Convertible Notes are unsecured and are subordinated to secured debt to the extent of the value of the assets securing such indebtedness.

The Convertible Notes are convertible at the option of the holder at any time prior to the close of business on the business day immediately preceding the maturity date. The conversion rate is initially 311.4295 shares of Common Stock per $1,000 principal amount of Convertible Notes (equivalent to an initial conversion price of approximately $3.21 per share of Common Stock). The conversion rate is subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase the conversion rate for a holder who elects to convert its Convertible Notes in connection with such a corporate event in certain circumstances.

The Company may not redeem the Convertible Notes prior to April 5, 2019, except in certain circumstances following a fundamental change (as defined in the indenture governing the Convertible Notes). The Company may redeem for all cash or any portion of the Convertible Notes, at its option, on or after April 5, 2019, if (terms below are as defined in the indenture governing the Convertible Notes):

(i) the last reported sale price of the Company's Common Stock has been at least 150% of the conversion price then in effect for at least 20 trading days (whether or not consecutive) during any 30 consecutive trading day period (including the last trading day of such period) ending on, and including, the trading day immediately preceding the date on which the Company provides notice of redemption; and

(ii) the Company has filed all reports that it is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, as applicable (other than current reports on Form 8-K), during the twelve months preceding the date on which the Company provides such notice.

The redemption price will be equal to 100% of the principal amount of the Convertible Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. No sinking fund is provided for the Convertible Notes.

If the Company undergoes a fundamental change, holders may require the Company to repurchase for cash all or any portion of their Convertible Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.

Net proceeds from the sale of the Convertible Notes were $109.1 million, after deducting the initial purchasers' discount and the offering expenses payable by the Company.

b) Credit Facility

At December 31, 2017, the Company had a revolving credit facility with a syndicate of lenders with a borrowing base of $300 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. On November 10, 2017, as a result of the Ninth Amendment to the credit agreement, the borrowing base of $300 million was reaffirmed and, among other things, the maturity date of the borrowing under the revolving credit facility was extended from October 1, 2018 to November 10, 2020. The next re-determination of the borrowing base is due to occur no later than May 2018.

Amounts drawn down under the revolving credit facility bear interest, at the Company's option, at the USD LIBOR rate plus a margin ranging from 2.15% to 3.65% (December 31, 2016 - 2.00% to 3.00%), or an alternate base rate plus a margin ranging from 1.15% to 2.65%, in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. At December 31, 2017 the weighted-average interest rate on the balance outstanding on the Company's revolving credit facility was approximately 3.64%. Undrawn amounts under the revolving credit facility bear interest from 0.54% to 0.91% (December 31, 2016 - 0.75%) per annum, based on the average daily amount of unused commitments. A letter of credit participation fee of 0.25% per annum will accrue on the average daily amount of letter of credit exposure.

The Company’s revolving credit facility is guaranteed by and secured against the assets of certain of the Company’s subsidiaries (the "Credit Facility Group"). Under the terms of the credit facility, the Company is subject on certain restrictions on its ability to distribute funds to entities outside of the Credit Facility Group, including restrictions on the ability to pay dividends to shareholders of the Company.

c) Interest expense

The following table presents total interest expense recognized in the accompanying consolidated statements of operations:



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017		2016		2015
Contractual interest and other financing expenses	$	11,467	$	8,454	$	—
Amortization of debt issuance costs	2,415		5,691		—
	$	13,882	$	14,145	$	—

The Company incurred debt issuance costs in connection with the issuance of the Convertible Notes and its revolving credit facility. As at December 31, 2017, the balance of unamortized debt issuance costs has been presented as a direct deduction against the carrying amount of debt and is being amortized to interest expense using the effective interest method over the term of the debt.

7. Share Capital

The Company’s authorized share capital consists of 595,000,002 shares of capital stock, of which 570 million are designated as Common Stock, par value $0.001 per share, 25 million are designated as Preferred Stock, par value $0.001 per share, and two shares are designated as special voting stock, par value $0.001 per share.

As at December 31, 2017, outstanding share capital consists of 385,191,042 shares of Common Stock of the Company, 4,422,776 exchangeable shares of Gran Tierra Exchangeco Inc., (the "Exchangeco exchangeable shares") and 1,688,889 exchangeable shares of Gran Tierra Goldstrike Inc. (the "Goldstrike exchangeable shares"). The Exchangeco exchangeable shares were issued upon the acquisition of Solana. The Goldstrike exchangeable shares were issued upon the business combination between Gran Tierra Energy Inc., an Alberta corporation, and Goldstrike, Inc., which is now the Company. The redemption date for the Exchangeco exchangeable shares and the Goldstrike exchangeable shares is a date to be established by the applicable Board of Directors.

The holders of shares of Common Stock are entitled to one vote for each share on all matters submitted to a stockholder vote and are entitled to share in all dividends that the Company’s Board of Directors, in its discretion, declares from legally available funds. The holders of Common Stock have no pre-emptive rights, no conversion rights, and there are no redemption provisions applicable to the shares. Holders of exchangeable shares have substantially the same rights as holders of shares of Common Stock. Each exchangeable share is exchangeable into one share of Common Stock of the Company.



	Shares of Common Stock		Exchangeable Shares of Gran Tierra Exchangeco Inc.		Exchangeable Shares of Gran Tierra Goldstrike Inc.
Balance, December 31, 2016	390,807,194		4,812,592		3,387,302
Exchange of exchangeable shares	2,088,229		(389,816	)	(1,698,413	)
Shares repurchased and canceled	(7,704,381	)	—		—
Balance, December 31, 2017	385,191,042		4,422,776		1,688,889

Share Repurchase Program

On February 6, 2017, the Company announced that it had implemented a share repurchase program (the “2017 Program”) through the facilities of the Toronto Stock Exchange (“TSX”), the NYSE American and eligible alternative trading platforms in Canada and the United States. Under the 2017 Program, the Company is able to purchase at prevailing market prices up to 19,540,359 shares of Common Stock, representing 5.0% of the issued and outstanding shares of Common Stock as of January 27, 2017. Shares purchased pursuant to the 2017 Program will be canceled. The 2017 Program expired on February 7, 2018.

Equity Compensation Awards

The Company has an equity compensation program in place for its executives and employees. Equity compensation grants vest either based solely on recipient's continued employment or achievement of certain key measures of performance. Equity awards consist 80% of Performance Stock Units (“PSUs”) and 20% of stock options. The Company’s equity compensation awards outstanding as at December 31, 2017, include PSUs, deferred share units (“DSUs”), restricted stock units (“RSUs”) and stock options.

In accordance with the 2007 Equity Incentive Plan, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 23,306,100 shares to 39,806,100 shares.

The following table provides information about PSU, DSU, RSU and stock option activity for the year ended December 31, 2017:



	PSUs		DSUs	RSUs		Stock Options
	Number of Outstanding Share Units		Number of Outstanding Share Units	Number of Outstanding Share Units		Number of Outstanding Stock Options		Weighted Average Exercise Price /Stock Option ($)
Balance, December 31, 2016	3,362,717		208,698	359,145		9,239,478		$	4.16
Granted	3,422,170		247,070	—		2,029,035		2.54
Exercised	—		—	(224,548	)	—		—
Forfeited	(652,936	)	—	(12,507	)	(911,154	)	(4.79		)
Expired	—		—	—		(1,396,667	)	(4.65		)
Balance, December 31, 2017	6,131,951		455,768	122,090		8,960,692		$	3.65
Exercisable, at December 31, 2017						5,044,267		$	4.33
Vested, or expected to vest, at December 31, 2017, through the life of the options						8,792,816		$	3.67

Stock-based compensation expense for the year ended December 31, 2017, was $9.8 million (December 31, 2016 - $6.3 million; December 31, 2015 - $2.7 million) and was primarily recorded in G&A expenses.

At December 31, 2017, there was $13.7 million (December 31, 2016 - $10.0 million) of unrecognized compensation cost related to unvested PSUs, RSUs and stock options which is expected to be recognized over a weighted average period of 1.6

years. The weighted-average remaining contractual term of options vested, or expected to vest, at December 31, 2017 was 2.9 years.

PSUs

PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company's

Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest

after three years, subject to the continued employment of the grantee. The number of PSUs that vest may range from zero to 200% of the target number granted based on the Company’s performance with respect to the applicable performance targets. The performance targets for the PSUs outstanding as at December 31, 2017, were as follows:

(i) 50% of the award is subject to targets relating to the total shareholder return (“TSR”) of the Company against a group of

peer companies

(ii) 25% of the award is subject to targets relating to net asset value ("NAV") of the Company per share and NAV is based on

before tax net present value discounted at 10% of proved plus probable reserves; and

(iii) 25% of the award is subject to targets relating to the execution of corporate strategy.

The compensation cost of PSUs is subject to adjustment based upon the attainability of these performance targets. No

settlement will occur with respect to the portion of the PSU award subject to each performance target for results below the

applicable minimum threshold for that target. PSUs in excess of the target number granted will vest and be settled if

performance exceeds the targeted performance goals. The Company currently intends to settle the PSUs in cash.

DSUs and RSUs

DSUs and RSUs entitle the holder to receive, either the underlying number of shares of the Company's Common Stock upon

vesting of such units or, at the option of the Company, a cash payment equal to the value of the underlying shares. The

Company's historic practice has been to settle RSUs in cash and the Company currently intends to settle the RSUs and DSUs

outstanding as at December 31, 2017 in cash, and, therefore, DSUs and RSUs are accounted for as liability instruments. Once a DSU or RSU is vested, it is immediately settled. During the year ended December 31, 2017, DSUs were granted to directors and will vest 100% at such time the grantee ceases to be a member of the Board of Directors. For the year ended December 31, 2017, the Company paid $0.6 million to cash settle RSUs (2016 - $1.2 million and 2015 - $1.4 million).

Stock Options

Each stock option permits the holder to purchase one share of Common Stock at the stated exercise price. The exercise price equals the market price of a share of Common Stock at the time of grant. Stock options generally vest over three years. The term of stock options granted starting in May of 2013 is five years or three months after the grantee’s end of service to the Company, whichever occurs first. Stock options granted prior to May of 2013 continue to have a term of ten years or three months after the end of the grantee’s service to the Company, whichever occurs first.

For the year ended December 31, 2017, no stock options were exercised and no cash proceeds were received (2016 – 2,165,370 options exercised and shares issued; 2015 – 390,000 options exercised and shares issued).

At December 31, 2017, the weighted average remaining contractual term of outstanding stock options was 2.9 years and of exercisable stock options was 2.5 years.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table:



	Year Ended December 31,
	2017		2016		2015
Dividend yield (per share)	Nil		Nil		Nil
Volatility	51% to 53%		50% to 54%		46% to 50%
Weighted average volatility	52	%	52	%	48	%
Risk-free interest rate	1.75% to 2.10%		0.94% to 1.78%		1.20% to 1.68%
Expected term	4-5 years		4-5 years		4-5 years

The weighted average grant date fair value for options granted in the year ended December 31, 2017, was $1.11 (2016 - $1.14; 2015 - $1.24). The weighted average grant date fair value for options vested in the year ended December 31, 2017, was $1.31 (2016 - $1.52; 2015 - $2.38). The total fair value of stock options vested during year ended December 31, 2017, was $2.5 million (2016 - $2.8 million; 2015 - $6.8 million).

Weighted Average Shares Outstanding

For the year ended December 31, 2017, 9,681,304 options, on a weighted average basis, (2016 - 10,662,034 options; 2015 - 13,432,287 options) were excluded from the diluted loss per share calculation as the options were anti-dilutive.

8. Asset Retirement Obligation

Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016
Balance, beginning of year	$	43,357		$	33,224
Liability incurred	3,403			2,606
Settlements	(1,507		)	(872		)
Accretion	3,825			2,789
Revisions in estimated liability	(4,095		)	(6,856		)
Liabilities associated with assets sold	(16,932		)	(3,257		)
Liabilities assumed in acquisitions	3,513			15,723
Balance, end of year	$	31,564		$	43,357

Asset retirement obligation - current	$	323		$	5,215
Asset retirement obligation - long-term	31,241			38,142
Balance, end of year	$	31,564		$	43,357

For the year ended December 31, 2017, settlements included cash payments of $1.3 million with the balance in accounts payable and accrued liabilities at December 31, 2017 (December 31, 2016 - $0.6 million). Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling asset retirement obligations. At December 31, 2017, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was $12.7 million (December 31, 2016 - $12.0 million). These assets were accounted for as restricted cash and cash equivalents on the Company's balance sheet.

9. Taxes

The income tax expense reported differs from the amount computed by applying the U.S. statutory rate to loss before income taxes for the following reasons:



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2016			2015
Income (Loss) before income taxes
United States	$	(51,215	)	$	(23,986	)	$	(14,061	)
Foreign	88,545			(626,248		)	(354,027		)
	37,330			(650,234		)	(368,088		)
	35		%	35		%	35		%
Income tax expense (recovery) expected	13,066			(227,582		)	(128,831		)
Impact of foreign taxes⁽¹⁾	12,310			(9,799		)	(13,087		)
Other local taxes	1,056			1,998			2,354
Stock-based compensation	2,001			1,955			919
Increase in valuation allowance	52,269			47,675			37,691
Sale of Peru and Brazil business units	(12,527		)	—			—
Non-deductible third party royalty in Colombia	3,194			2,550			3,416
Other permanent differences	(2,331		)	(1,466		)	(2,521		)
Total income tax expense (recovery)	$	69,038		$	(184,669	)	$	(100,059	)

Current income tax expense
United States	$	3,457		$	1,818		$	1,070
Foreign	20,865			18,304			14,313
	24,322			20,122			15,383
Deferred income tax expense (recovery)
Foreign⁽²⁾	44,716			(204,791		)	(115,442		)
Total income tax expense (recovery)	$	69,038		$	(184,669	)	$	(100,059	)

⁽¹⁾Impact of foreign taxes in the rate reconciliation are tax effected at the 35% statutory rate and were primarily due to higher income tax rates in Colombia. Impact of foreign taxes for the years ended December 31, 2017, 2016 and 2015, included $8.0 million (expense), $23.3 million (recovery) and $11.8 million (recovery), respectively, in Colombia.

⁽²⁾ The deferred tax recovery for the year ended December 31, 2016, included $201.3 million associated with the ceiling test impairment loss in Colombia.

Undistributed earnings of foreign subsidiaries as of December 31, 2017, were considered to be permanently reinvested. A determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.

In the fourth quarter of 2016, the Colombian government approved tax legislation consolidating the corporate Income and CREE taxes into a single income tax at 40% for 2017 (including a surtax of 6%), 37% for 2018 (including a surtax of 4%) and 33% for 2019 and onwards. The tax rates applied to the calculation of deferred income taxes, before valuation allowances, have been adjusted to reflect these changes. In the same legislation, the Colombian government also instituted a 5% dividend tax on distributions of previously taxed earnings from 2017 and onwards. The Law also increased the corporate minimum presumptive income tax from 3% to 3.5%. The tax is imposed on a taxpayer’s net equity at the prior year-end when the presumptive income exceeds actual taxable profits.

The US government enacted the Tax Cuts and Jobs Act of 2017 (“TCJA”) on December 22, 2017. As of December 31, 2017, the Company is still evaluating the complete tax effects of the enactment of the TCJA. However, the Company has determined a reasonable estimate of the impact of the TCJA on its existing deferred tax balances and the one-time transition tax. Based on this estimate, the Company has determined that the there is no current tax expense impact to its financial statements as a result of the TCJA. The Company has also calculated an estimated deferred tax asset impact of $59 million, which is subject to a full valuation allowance because its recognition does not meet the “more-likely-than-not” threshold. Of the estimated amount, $1.1 million relates to the remeasurement of certain deferred tax assets and liabilities based on the rate at which they are expected to reverse in the future.

As noted above, the Company is still evaluating the complete tax effects of the enactment of the TCJA and there are a number of uncertainties and ambiguities as to the interpretation and application of many of the provisions in the TCJA. In the absence

of guidance on these matters and until the 2017 tax returns are finalized, which the Company expects to occur in October 2018, the Company expects to use what it believes are reasonable interpretations and assumptions in applying the TCJA for purposes of determining its cash tax liabilities and results of operations, which may change as it receives additional clarification and implementation guidance. Despite the fact that the Company has not prepared its tax returns for 2017, and therefore cannot provide a final estimate of 2017 foreign earning and profits, but considering the consistency of the Company’s 2017 foreign operations with prior years, the Company’s overall analysis of the one-time transition tax has not identified, nor does it expect to identify, any overall material adverse effect on its tax liability and financial condition.



	As at December 31,
(Thousands of U.S. Dollars)	2017			2016
Deferred Tax Assets
Tax benefit of operating loss carryforwards	$	60,460		$	74,604
Tax basis in excess of book basis	62,768			187,651
Foreign tax credits and other accruals	70,157			48,341
Tax benefit of capital loss carryforwards	52,575			32,278
Deferred tax assets before valuation allowance	245,960			342,874
Valuation allowance	(188,650		)	(341,263		)
	57,310			1,611
Deferred Tax Liabilities	28,417			107,230
Net Deferred Tax Assets (Liabilities)⁽¹⁾	$	28,893		$	(105,619	)

⁽¹⁾Effective November 1, 2016, several of Gran Tierra's subsidiaries executed intercompany sale agreements whereby certain depreciable assets were transferred within the consolidated Gran Tierra group. The purpose of the transaction was to improve the efficiency of Gran Tierra's operating and tax structures. The restructuring resulted in a consolidation of certain assets into a single entity in Colombia, an increase in the depreciable tax basis of the assets transferred, and current income taxes payable as at December 31, 2016, as a result of the capital gains taxes incurred. GAAP prohibited the recognition of current and deferred income taxes for intra-entity transfers until an asset leaves the consolidated group, therefore, the current and deferred income tax effect of the restructuring was deferred and recognized as prepaid income taxes at December 31, 2016. At January 1, 2017, the impact of the November 1, 2016, intercompany asset transfers was recognized pursuant to adoption of ASU 2016-16 (Note 2), which resulted in a material increase in the tax basis of certain Colombian assets. Accordingly, for 2017, this resulted in the Company realizing a change in its net deferred balance from a deferred tax liability at December 31, 2016, to a deferred tax asset at December 31, 2017.



	As at December 31,
(Thousands of U.S. Dollars)	2017		2016
Operating loss carryforwards	$	199,138	$	257,023
Capital loss carryforwards	$	288,322	$	239,095
Of the operating loss and capital loss carryforwards, losses generated by the foreign subsidiaries of the Company.	$	392,053	$	496,118

In certain jurisdictions, operating loss carryforwards expire between 2018 and 2037, while certain other jurisdictions allow operating losses to be carried forward indefinitely. Capital losses can be carried forward indefinitely.

The valuation allowance decreased by $152.6 million during the year ended December 31, 2017. The change in the valuation allowance was primarily due to $212.1 million decrease as a result of the sale of Peru and Brazil business units.This is partially offset by $86.7 million increase in capital losses generated in Luxembourg as a result of the sale of Brazil, $20.9 million increase in foreign tax credits in the U.S. arising from the U.S. legislated one-time deemed repatriation of foreign earning, $7.1 million increase in tax basis as a result of the 2016 intercompany asset transfers recognized on January 1, 2017, pursuant to adoption of ASU 2016-16 and $10.2 million of losses incurred in the U.S., Colombia and Canada as well as other credits. These future tax benefits are fully off-set by valuation allowances, as their recognition does not meet the “more-likely-than-not” threshold.

The Company and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and certain other foreign jurisdictions. The Company is potentially subject to income tax examinations for open tax years 2009 through 2016 in certain

jurisdictions. To the extent interest and penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the consolidated statement of operations.

On December 23, 2014, the Colombian Congress passed legislation which imposed an equity tax levied on Colombian operations for 2015, 2016 and 2017. The equity tax was calculated based on a legislated measure, which was based on the Company’s Colombian legal entities' balance sheet equity for tax purposes at January 1, 2015. This measure was subject to adjustment for inflation in future years. The equity tax rates for January 1, 2015, 2016 and 2017, were 1.15%, 1% and 0.4%, respectively. The legal obligation for each year's equity tax liability arose on January 1 of each year; therefore, the Company recognized the annual amount of $1.2 million, $3.1 million and $3.8 million for the equity tax expense in the consolidated statement of operations for the years ended December 31, 2017, 2016 and 2015. These amounts were paid in May and September of each year and at December 31, 2017, accounts payable included nil (December 31, 2016 - nil).

10. Accounts Payable and Accrued Liabilities



	As at December 31,
(Thousands of U.S. Dollars)	2017		2016
Trade	$	99,146	$	80,072
Royalties	6,867		4,542
Employee compensation	8,767		8,152
Other	11,391		14,285
	$	126,171	$	107,051

11. Commitments and Contingencies

Purchase Obligations, Firm Agreements and Leases

As at December 31, 2017, future minimum payments under non-cancelable agreements with remaining terms in excess of one year were as follows:



	Year ending December 31
	Total		2018		2019		2020		2021		2022		Thereafter
(Thousands of U.S. Dollars)
Oil transportation services	$	10,895	$	3,842	$	3,842	$	3,211	$	—	$	—	$	—
Facility construction	27,006		5,446		5,446		5,461		5,446		5,207		—
Operating leases	4,554		1,840		1,267		1,240		207		—		—
Software and telecommunication	961		339		320		302		—		—		—
	$	43,416	$	11,467	$	10,875	$	10,214	$	5,653	$	5,207	$	—

Gran Tierra leases certain office space, compressors, vehicles, equipment and housing. Total rent expense for the year ended December 31, 2017, was $3.2 million (year ended December 31, 2016 – $3.2 million; year ended December 31, 2015 - $4.0 million).

Indemnities

Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated. The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.

Letters of credit

At December 31, 2017, the Company had provided promissory notes totaling $76.0 million (December 31, 2016 - $96.8 million) as security for letters of credit relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements.

Contingencies

The ANH and Gran Tierra are engaged in ongoing discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Based on the Company's understanding of the ANH's position, the estimated compensation, which would be payable if the ANH’s interpretation is correct, could be up to $50.8 million as at December 31, 2017. At this time, no amount has been accrued in the consolidated financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

In addition to the above, Gran Tierra has a number of lawsuits and claims pending. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Gran Tierra records costs as they are incurred or become probable and determinable.

12. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk

Financial Instruments

At December 31, 2017, the Company’s financial instruments recognized in the balance sheet consist of; cash and cash equivalents; restricted cash and cash equivalents; accounts receivable; investments; derivatives; accounts payable and accrued liabilities; long-term debt; PSU liability included in other long-term liabilities; and RSU liability included in accounts payable and accrued liabilities and other long-term liabilities.

Fair Value Measurement

The fair value of investment, derivatives and RSU and PSU liabilities are being remeasured at the estimated fair value at the end of each reporting period.

The fair value of the short-term portion of the investment which was received as consideration on the sale of the Company's Peru business unit was estimated using quoted prices at December 31, 2017 and the market exchange rate at that time. The fair value of the long-term portion of the investment restricted by escrow conditions was estimated using observable and unobservable inputs; factors that were evaluated included quoted market prices, precedent comparable transactions, risk free rate, measures of market risk volatility, estimates of the Company's and Sterling’s cost of capital and quotes from third parties.

The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted

market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the

reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of

whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally,

the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its

potential repayment obligations associated with the derivative transactions.

The fair value of the RSU liability was estimated based on quoted market prices in an active market. The fair value of the PSU

liability was estimated based on option pricing model using the inputs, such as quoted market prices in an active market, and PSU performance factor.

The fair value of investments, derivatives, RSU, PSU and DSU liabilities at December 31, 2017, and December 31, 2016 were as follows:



	As at December 31,
(Thousands of U.S. Dollars)	2017		2016
Investment - current and long-term assets	$	44,202	$	—
Foreign currency derivative asset	302		578
	$	44,504	$	578

Commodity price derivative liability	$	21,151	$	3,824
RSU, PSU and DSU liability	11,430		3,907
	$	32,581	$	7,731

The following table presents losses or gains on financial instruments recognized in the accompanying consolidated statements of operations:



(Thousands of U.S. Dollars)	Year Ended December 31,
	2017			2016			2015
Commodity price derivative loss	$	17,327		$	7,370		$	—
Foreign currency derivative (gain) loss	(1,287		)	(1,016		)	692
Investment gain	(111		)	—			—
Trading securities loss	—			3,925			1,335
	$	15,929		$	10,279		$	2,027

These gains or losses are presented as financial instruments loss in the consolidated statements of operations and cash flows.

Investment gain related to fair value gains on the Sterling shares Gran Tierra received in connection with the sale of its Peru business unit in December 2017 (Note 5). For the year ended December 31, 2017 these investment gains were unrealized.

All trading securities were sold during the year ended December 31, 2016, and the trading securities loss represented a realized loss. The cash proceeds were included in cash flows from investing activities in the Company's consolidated statements of cash flows because these securities were received in connection with the sale of the Company's Argentina business unit in 2014. For the year ended December 31, 2015, the trading securities loss represented an unrealized loss.

Financial instruments not recorded at fair value include the Convertible Notes (Note 6). At December 31, 2017, the carrying amount of the Convertible Notes was $111.0 million, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair value was $129.1 million. The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.

At December 31, 2017, the fair value of current portion of the investment, RSU and DSU liability was determined using Level 1 inputs, the fair value of derivatives and PSUs was determined using Level 2 inputs and the fair value of the long-term portion of the investment restricted by escrow conditions was determined using Level 3 inputs. The table below presents a roll-forward of the long-term portion of the investment:



	Year Ended December 31,
(Thousands of U.S. Dollars)	2017		2016
Opening balance	$	—	$	—
Acquisition	19,091		—
Unrealized gain on valuation	56		—
Closing balance	$	19,147	$	—

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The fair value of debt

is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the

difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk.

The credit spread (premium or discount) is determined by comparing the Company’s Convertible Notes and revolving credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The disclosure in the paragraph above regarding the fair value of the Company’s revolving credit facility was determined using an income approach using Level 3 inputs. The disclosure in the paragraph above regarding the fair value of the Convertible Notes was determined using Level 2 inputs based on the indicative pricing published by certain investment banks or trading levels of the Convertible Notes, which are not listed on any securities exchange or quoted on an inter-dealer automated quotation system. The disclosure in the paragraph above regarding the fair value of cash and cash equivalents and restricted cash and cash equivalents was based on Level 1 inputs.

The Company’s non-recurring fair value measurements include asset retirement obligations. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. The significant level 3 inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free interest rate, inflation rates and estimated dates of abandonment. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets.

Commodity Price Derivatives

The Company utilizes commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.

At December 31, 2017, the Company had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Sold Swap ($/bbl, Weighted Average)		Purchased Call ($/bbl, Weighted Average)
Swaps: January 1, to December 31, 2018	5,000	ICE Brent	$	55.90	n/a
Participating Swaps: January 1, to December 31, 2018	5,000	ICE Brent	$	52.50	$	56.11

Foreign Exchange Risk and Foreign Currency Derivatives

The Company utilizes foreign currency derivatives to manage the variability in cash flows associated with the Company's forecasted Colombian peso ("COP") denominated expenses, predominantly operating costs, general and administrative costs and transportation costs.

At December 31, 2017, the Company had outstanding foreign currency derivative positions as follows:



Period and type of instrument	Amount Hedged (Millions COP)	U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)	Reference	Purchased Call (COP)	Sold Put (COP, Weighted Average)
Collars: January 1, 2018 to December 31, 2018	174,000	58,311	COP	3,000	3,107

The Company's cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company's derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. These cash settlements were included in cash flows from operating activities in the Company's consolidated statements of cash flows.

While the use of these derivative instruments may limit or partially reduce the downside risk of adverse commodity price and foreign exchange movements, their use also may limit future income and gains from favorable commodity price and foreign exchange movements.

Unrealized foreign exchange gains and losses primarily result from fluctuation of the U.S. dollar to the Colombian peso due to Gran Tierra’s current and deferred tax liabilities, which are monetary liabilities mainly denominated in the local currency of the Colombian operations. As a result, foreign exchange gains and losses 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 $10,000 for each one peso decrease in the exchange rate of the Colombian peso to one U.S. dollar. This effect was calculated based on the Company's December 31, 2017, deferred tax balances.

For the year ended December 31, 2017, 98% (year ended December 31, 2016 - 97%, year ended December 31, 2015 - 97%) of the Company's oil and natural gas sales were generated in Colombia. In Colombia, the Company receives 100% of its revenues in U.S. dollars and the majority of its capital expenditures are in U.S. dollars or are based on U.S. dollar prices.

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, restricted cash and accounts receivable. The carrying value of cash and cash equivalents, restricted cash and accounts receivable reflects management’s assessment of credit risk.

At December 31, 2017, cash and cash equivalents and restricted cash included balances in bank accounts, term deposits and certificates of deposit, placed with financial institutions with investment grade credit ratings.

Most of the Company’s accounts receivable relate to uncollateralized sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. For the year ended December 31, 2017, the Company had three customers which were significant to the Colombian segment.

To reduce the concentration of exposure to any individual counterparty, the Company utilizes a group of investment-grade rated financial institutions, for its derivative transactions. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments.

13. Supplemental Cash Flow Information

The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's consolidated balance sheet that sum to the total of the same such amounts shown in the consolidated statements of cash flows:



(Thousands of U.S. Dollars)	As at December 31,
	2017		2016		2015
Cash and cash equivalents	$	12,326	$	25,175	$	145,342
Restricted cash and cash equivalents - current	11,787		8,322		92
Restricted cash and cash equivalents - long-term⁽¹⁾	2,565		9,770		3,317
	$	26,678	$	43,267	$	148,751

⁽¹⁾The long-term portion of restricted cash is included in other long-term assets on the Company's balance sheet.

Net changes in assets and liabilities from operating activities were as follows:



	Year Ended December 31,
	2017			2016			2015
Accounts receivable and other long-term assets	$	(2,494	)	$	(29	)	$	44,365
Derivatives	—			(3,546		)	—
Inventory	(78		)	5,510			(1,571		)
Other prepaids	2,674			(615		)	152
Accounts payable and accrued and other long-term liabilities	15,617			(9,691		)	(33,743		)
Prepaid tax and taxes receivable and payable	(44,936		)	(2,966		)	(48,251		)
Net changes in assets and liabilities from operating activities	$	(29,217	)	$	(11,337	)	$	(39,048	)

The following table provides additional supplemental cash flow disclosures:



	Year Ended December 31,
	2017		2016		2015
Cash paid for income taxes	$	54,505	$	64,067	$	39,422
Cash paid for interest	$	9,684	$	5,624	$	—

Non-cash investing activities:
Net liabilities related to property, plant and equipment, end of year	$	76,352	$	55,181	$	33,923

See Note 5 in these consolidated financial statements for disclosure regarding non-cash share consideration received in connection with the Company's disposition of its Peru Business unit. In the year ended December 31, 2016, the purchase price paid for acquisition of Petroamerica Oil Corp. included $25.8 million of Gran Tierra's Common Stock.

14. Subsequent Event

On February 15, 2018, Gran Tierra Energy International Holdings Ltd., an indirect, wholly owned subsidiary of the Company, issued $300 million aggregate principal amount of its 6.25% Senior Notes due 2025 (the "2025 Notes") in a private placement transaction. The 2025 Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 2025 Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Supplementary Data (Unaudited)

1) Oil and Gas Producing Activities

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), the Company is making certain supplemental disclosures about its oil and gas exploration and production operations.

A. Estimated Proved NAR Reserves

The following table sets forth Gran Tierra's estimated proved NAR reserves and total net proved developed and undeveloped reserves as of December 31, 2014, 2015, 2016 and 2017, and the changes in total net proved reserves during the three-year period ended December 31, 2017.

The net proved reserves represent management’s best estimate of proved oil and natural gas reserves after royalties. Reserve estimates for each property are prepared internally each year and 100% of the reserves at December 31, 2017, have been evaluated by independent qualified reserves consultants, McDaniel & Associates Consultants Ltd.

The reserve estimation process requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property, and demonstrate reasonable certainty that they are recoverable from known reservoirs under economic and operating conditions that existed at year end. The determination of oil and natural gas reserves is complex and requires significant judgment. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. The process of estimating oil and gas reserves is complex and requires significant judgment, as discussed in Item 1A. “Risk Factors”. See “Critical Accounting Estimates” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for a description of Gran Tierra’s reserves estimation process.



	Colombia
	Liquids ⁽¹⁾		Gas
	(Mbbl)		(MMcf)
Proved NAR Reserves, December 31, 2014	34,044		983
Extensions and discoveries	410		526
Production	(6,872	)	(318	)
Revisions of previous estimates	5,804		632
Proved NAR Reserves, December 31, 2015	33,386		1,823
Purchases of reserves in place	20,568		—
Extensions and discoveries	1,142		435
Production	(8,125	)	(592	)
Revisions of previous estimates	(1,093	)	(71	)
Proved NAR Reserves, December 31, 2016	45,878		1,595
Purchases of reserves in place	2,041		—
Extensions and discoveries	9,543		—
Improved recoveries	2,461		—
Technical revisions	7,627		1,077
Discoveries	873		—
Production	(9,469	)	(588	)
Proved NAR Reserves, December 31, 2017	58,954		2,084

Proved Developed Reserves NAR, December 31, 2015	28,513		1,346
Proved Developed Reserves NAR, December 31, 2016	35,529		1,468
Proved Developed Reserves NAR, December 31, 2017	39,487		1,431

Proved Undeveloped Reserves NAR, December 31, 2015	4,873		477
Proved Undeveloped Reserves NAR, December 31, 2016	10,349		127
Proved Undeveloped Reserves NAR, December 31, 2017	19,467		653

⁽¹⁾ At December 31, 2017, 2016 , 2015 and 2014 , liquids reserves are 100% oil.

B. Capitalized Costs

Capitalized costs for Gran Tierra's oil and gas producing activities consisted of the following at the end of each of the years in the two-year period ended December 31, 2017:



(Thousands of U.S. Dollars)	Proved Properties		Unproved Properties		Accumulated Depletion, Depreciation and Impairment			Net Capitalized Costs
Colombia	$	2,810,796	$	464,948	$	(2,181,715	)	$	1,094,029
Balance, December 31, 2017	$	2,810,796	$	464,948	$	(2,181,715	)	$	1,094,029

Colombia	$	2,435,124	$	561,463	$	(2,059,073	)	$	937,514
Brazil	217,047		18,445		(180,779		)	54,713
Peru	—		67,866		—			67,866
Balance, December 31, 2016	$	2,652,171	$	647,774	$	(2,239,852	)	$	1,060,093

C. Costs Incurred

The following tables present costs incurred for Gran Tierra's oil and gas property acquisitions, exploration and development for the respective years:



(Thousands of U.S. Dollars)	Colombia		Brazil		Peru		Total
Balance, December 31, 2014	$	1,795,532	$	200,406	$	394,531	$	2,390,469
Property acquisition costs
Proved	—		—		—		—
Unproved	—		—		—		—
Exploration costs	17,512		12,466		50,347		80,325
Development costs	69,910		7,472		—		77,382
Balance, December 31, 2015	1,882,954		220,344		444,878		2,548,176
Property acquisition costs
Proved	408,793		—		—		408,793
Unproved	500,081		—		—		500,081
Exploration costs	33,362		6,086		4,985		44,433
Development costs	72,601		9,060		—		81,661
Balance, December 31, 2016	2,897,791		235,490		449,863		3,583,144
Property acquisition costs
Proved	28,405		1,565		—		29,970
Unproved	8,649		—		4,314		12,963
Exploration costs	64,003		—		—		64,003
Development costs	171,498		—				171,498
Balance, December 31, 2017	$	3,170,346	$	237,055	$	454,177	$	3,861,578

D. Results of Operations for Oil and Gas Producing Activities



(Thousands of U.S. Dollars)	Colombia
Year Ended December 31, 2017
Oil and natural gas sales	$	413,316
Production costs	(132,829		)
Exploration expenses	—
DD&A expenses	(126,453		)
Asset Impairment	—
Income tax expense	(64,000		)
Results of Operations	$	90,034

Year Ended December 31, 2016
Oil and natural gas sales	$	280,872
Production costs	(116,141		)
Exploration expenses	—
DD&A expenses	(132,569		)
Asset Impairment	(514,314		)
Income tax expense	187,168
Results of Operations	$	(294,984	)

Year Ended December 31, 2015
Oil and natural gas sales	$	269,035
Production costs	(109,406		)
Exploration expenses	—
DD&A expenses	(167,701		)
Asset Impairment	(235,069		)
Income tax expense	102,014
Results of Operations	$	(141,127	)

E. Standardized Measure of Discounted Future Net Cash Flows and Changes

The following disclosure is based on estimates of net proved reserves and the period during which they are expected to be produced. Future cash inflows are computed by applying the twelve month period unweighted arithmetic average of the price as of the first day of each month within that twelve month period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions to Gran Tierra’s after royalty share of estimated annual future production from proved oil and gas reserves.



	Colombia		Brazil
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period
2017	$	43.00	$	—
2016	$	31.67	$	31.42
2015	$	43.51	$	37.72
Weighted average production costs
2017	$	15.73	$	—
2016	$	15.42	$	12.19
2015	$	12.11	$	8.30

Future development and production costs to be incurred in producing and further developing the proved reserves are based on year end cost indicators. Future income taxes are computed by applying year end statutory tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows. Discounted future net cash flows are calculated using 10% mid-year discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results.

The Company believes this information does not in any way reflect the current economic value of its oil and gas producing properties or the present value of their estimated future cash flows as:


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


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


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

The standardized measure of discounted future net cash flows from Gran Tierra's estimated proved oil and gas reserves is as follows:



(Thousands of U.S. Dollars)	Colombia			Brazil			Total
December 31, 2017
Future cash inflows	$	2,570,551		$	—		$	2,570,551
Future production costs	(1,082,651		)	—			(1,082,651		)
Future development costs	(212,712		)	—			(212,712		)
Future asset retirement obligations	(33,796		)	—			(33,796		)
Future income tax expense	(146,652		)	—			(146,652		)
Future net cash flows	1,094,740			—			1,094,740
10% discount	(246,692		)	—			(246,692		)
Standardized Measure of Discounted Future Net Cash Flows	$	848,048		$	—		$	848,048

December 31, 2016
Future cash inflows	$	1,487,553		$	195,476		$	1,683,029
Future production costs	(803,208		)	(85,262		)	(888,470		)
Future development costs	(94,131		)	(23,975		)	(118,106		)
Future asset retirement obligations	(24,647		)	(1,200		)	(25,847		)
Future income tax expense	(28,446		)	(8,957		)	(37,403		)
Future net cash flows	537,121			76,082			613,203
10% discount	(117,263		)	(43,235		)	(160,498		)
Standardized Measure of Discounted Future Net Cash Flows	$	419,858		$	32,847		$	452,705

December 31, 2015
Future cash inflows	$	1,486,828		$	195,726		$	1,682,554
Future production costs	(697,071		)	(58,058		)	(755,129		)
Future development costs	(51,671		)	(15,660		)	(67,331		)
Future asset retirement obligations	(15,096		)	(1,200		)	(16,296		)
Future income tax expense	(196,981		)	(17,361		)	(214,342		)
Future net cash flows	526,009			103,447			629,456
10% discount	(119,100		)	(45,599		)	(164,699		)
Standardized Measure of Discounted Future Net Cash Flows	$	406,909		$	57,848		$	464,757

Changes in the Standardized Measure of Discounted Future Net Cash Flows

The following table summarizes changes in the standardized measure of discounted future net cash flows for Gran Tierra's proved oil and gas reserves during three years ended December 31, 2017:



(Thousands of U.S. Dollars)	2017			2016			2015
Balance, beginning of year	$	452,705		$	464,757		$	1,021,133
Sales and transfers of oil and gas produced, net of production costs	(193,197		)	(207,776		)	(160,242		)
Net changes in prices and production costs related to future production	(372,138		)	13,425			(918,746		)
Extensions, discoveries and improved recovery, less related costs	193,672			111			22,754
Previously estimated development costs incurred during the year	71,816			34,917			54,904
Revisions of previous quantity estimates	1,128,440			(263,713		)	144,603
Accretion of discount	(120,231		)	73,076			137,853
Purchases of reserves in place	7,416			186,393			—
Sales of reserves in place	(32,847		)	—			—
Net change in income taxes	(112,838		)	178,273			100,587
Changes in future development costs	(174,750		)	(26,758		)	61,911
Net increase (decrease)	395,343			(12,052		)	(556,376		)
Balance, end of year	$	848,048		$	452,705		$	464,757

2) Summarized Quarterly Financial Information



	Three Months Ended										Year Ended
(Thousands of U.S. Dollars, Except Per Share Amounts)	March 31, 2017		June 30, 2017			September 30, 2017		December 31, 2017			December 31, 2017
Oil and natural gas sales	$	94,659	$	96,128		$	103,768	$	127,179		$	421,734

Asset impairment	$	283	$	169		$	787	$	275		$	1,514

Net income (loss)	$	12,771	$	(6,807	)	$	3,130	$	(40,802	)	$	(31,708	)

Net income (Loss) per share - Basic and Diluted	$	0.03	$	(0.02	)	$	0.01	$	(0.10	)	$	(0.08	)



	Three Months Ended												Year Ended
(Thousands of U.S. Dollars, Except Per Share Amounts)	March 31, 2016			June 30, 2016			September 30, 2016			December 31, 2016			December 31, 2016
Oil and natural gas sales	$	57,403		$	71,713		$	68,539		$	91,614		$	289,269

Asset impairment	$	56,898		$	92,843		$	319,974		$	146,934		$	616,649

Net loss	$	(45,032	)	$	(63,559	)	$	(229,619	)	$	(127,355	)	$	(465,565	)

Loss per share - Basic and Diluted	$	(0.15	)	$	(0.21	)	$	(0.71	)	$	(0.38	)	$	(1.45	)

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule 13a-15(b) of the Exchange Act. Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of December 31, 2017, to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Gran Tierra, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2017. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Deloitte LLP, the independent registered public accounting firm, which audited our financial statements included in this Annual Report on Form 10-K as stated in their report which appears herein.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Report of Independent Registered Public Accounting Firm

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

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Gran Tierra Energy Inc. and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and Canadian generally accepted auditing standards, the consolidated financial statements as of and for the year ended December 31, 2017, of the Company and our report dated February 27, 2018, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are

required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte LLP

Chartered Professional Accountants

Calgary, Canada

February 27, 2018

Item 9B. Other Information

The Board of Directors of Gran Tierra Energy Inc. has established May 2, 2018 as the date of the Company’s 2018 Annual Meeting of Stockholders (the “2018 Annual Meeting”) and March 12, 2018, as the record date for determining stockholders entitled to notice of, and to vote at, the 2018 Annual Meeting. The time and location of the 2018 Annual Meeting will be as set forth in the Company’s proxy materials for the 2018 Annual Meeting.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required regarding our directors is incorporated herein by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our definitive Proxy Statement for the 2018 Annual Meeting of Stockholders (our “Proxy Statement”), a copy of which will be filed with the SEC within 120 days after December 31, 2017. For information with respect to our executive officers, see “Executive Officers of the Registrant” at the end of Part I of this report, following Item 4. “Mine Safety Disclosure.”

The information required regarding Section 16(a) beneficial ownership reporting compliance is incorporated by reference from the information contained in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement.

The information required with respect to procedures by which security holders may recommend nominees to our Board of Directors, the composition of our Audit Committee, and whether we have an “audit committee financial expert”, is incorporated by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our Proxy Statement.

Adoption of Code of Ethics

Gran Tierra has adopted a Code of Business Conduct and Ethics (the “Code”) applicable to all of its Board members, employees and executive officers, including its Chief Executive Officer (Principal Executive Officer), and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer). Gran Tierra has made the Code available on its website at www.grantierra.com.

Gran Tierra intends to satisfy the public disclosure requirements regarding (1) any amendments to the Code, or (2) any waivers under the Code given to Gran Tierra’s Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer by posting such information on its website at http://www.grantierra.com/governance.html.

Item 11. Executive Compensation

The information required regarding the compensation of our directors and executive officers is incorporated herein by reference from the information contained in the section entitled “Executive Compensation and Related Information” in our Proxy Statement, including under the subheadings “Director Compensation,” “Compensation Committee Report” and “Compensation Committee Interlocks and Insider Participation”.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Security Ownership of Certain Beneficial Owners and Management

The information required regarding security ownership of our 10% or greater stockholders and of our directors and management is incorporated herein by reference from the information contained in the section entitled “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement.

The following table provides certain information with respect to securities authorized for issuance under Gran Tierra’s equity compensation plans in effect as of the end of December 31, 2017:

Equity Compensation Plan Information



Plan category	(a) Number of securities to be issued upon exercise of outstanding options ⁽¹⁾	(b) Weighted average exercise price of outstanding options	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)⁽²⁾
Equity compensation plans approved by security holders	8,960,692	3.65	17,280,233
Equity compensation plans not approved by security holders	—	—	—
	8,960,692	3.65	17,280,233

⁽¹⁾ Includes shares reserved to be issued pursuant to stock options granted pursuant to the 2007 Equity Incentive Plan ("the Plan"), which is an amendment and restatement of our 2005 Equity Incentive Plan. This does not include any shares reserved to be issued relating to performance stock units ("PSU's"), deferred share units (DSU's") and restricted stock units ("RSU's"), which may be settled in cash or in shares of our common stock at our election, and for which management's intent to cash settle is reflected in the financial statement classification of these awards as financial liabilities.

⁽²⁾ In accordance with Item 201(d) of Regulation S-K, the figure in this column represents the total number of shares of our common stock remaining available for issuance under the Plan as of December 31, 2017, minus the awards reported in column (a), above. Note, pursuant to the terms of the Plan, the pool of shares available for grant thereunder is not actually reduced until an award is settled in shares of our common stock (as opposed to reducing the pool at the time of grant) At December 31, 2017, PSU's, DSU's and RSU's with respect to 6,709,809 shares were issued and outstanding and, after application of the fungible factor of 1.55, these outstanding awards would represent a 10,400,204 reduction to the securities remaining available for future issuance under the Plan if such awards were to be equity settled. Consistent with accounting treatment that reflects management's intent to cash settle, these amounts are not included in the above table as a reduction in the securities remaining available for future issuance. Pursuant to the provisions of the Plan, the number of securities remaining available for issuance is reduced by the aggregate balance of (i) stock options exercised and outstanding at a fungible factor of 1.0 shares and (ii) unit based awards at a fungible factor of 1.55 shares for each share of our common stock issued pursuant to any equity settled awards granted under the Plan. Accordingly, the number of shares available for future awards under the Plan may be different than the amount shown in this column.

The only equity compensation plan approved by our stockholders is our 2007 Equity Incentive Plan, which is an amendment and restatement of our 2005 Equity Plan.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required regarding related transactions is incorporated herein by reference from the information contained in the section entitled “Certain Relationships and Related Transactions” and, with respect to director independence, the section entitled “Proposal 1 - Election of Directors”, in our Proxy Statement.

Item 14. Principal Accounting Fees and Services

The information required is incorporated herein by reference from the information contained in the sections entitled “Principal Accountant Fees and Services” and “Pre-Approval Policies and Procedures” in the proposal entitled “Ratification of Selection of Independent Auditors” in our Proxy Statement.

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this Annual Report on Form 10-K:

(1) Financial Statements



	Page
Report of Independent Registered Public Accounting Firm	56
Consolidated Statements of Operations	57
Consolidated Balance Sheets	58
Consolidated Statements of Cash Flow	59
Consolidated Statements of Shareholders’ Equity	60
Notes to the Consolidated Financial Statements	61
Supplementary Data (Unaudited)	85

(2) Financial Statement Schedules

None.

(3) Exhibits



Exhibit No.	Description	Reference
2.2	Plan of Conversion, dated October 31, 2016.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.1	Certificate of Incorporation.	Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

3.2	Bylaws of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).

4.1	Details of the Goldstrike Special Voting Share.	Incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005, and filed with the SEC on April 21, 2006 (SEC File No. 333-111656).

4.2	Goldstrike Exchangeable Share Provisions.	Incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-KSB/A for the period ended December 31, 2005 and filed with the SEC on April 21, 2006 (SEC File No. 333-111656).

4.3	Provisions Attaching to the GTE–Solana Exchangeable Shares.	Incorporated by reference to Annex E to the Proxy Statement on Schedule 14A filed with the SEC on October 14, 2008 (SEC File No. 001-34018).

4.4	Indenture related to the 5.00% Convertible Senior Notes due 2021, dated as of April 6, 2016, between Gran Tierra Energy Inc. and U.S. Bank National Association	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

4.5	Form of 5.00% Convertible Senior Notes due 2021.	Incorporated by reference in Exhibit A to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

4.6	Subscription Receipt Agreement, dated July 8, 2016, by and between Gran Tierra Energy Inc. and Computershare Trust Company of Canada	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).



4.7	Form of Registration Rights Agreement.	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).

4.8	Indenture related to the 6.25% Senior Notes due 2025, dated as of February 15, 2018, between Gran Tierra Energy International Holdings Ltd., the Guarantors named therein and U.S. Bank National Association	Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).

4.9	Form of 6.25% Senior Notes due 2025	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).

10.1	Voting Exchange and Support Agreement by and between Goldstrike, Inc., 1203647 Alberta Inc., Gran Tierra Goldstrike Inc. and Olympia Trust Company dated as of November 10, 2005.	Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the SEC on November 10, 2005 (SEC File No. 333-111656).

10.2	Voting and Exchange Trust Agreement, dated as of November 14, 2008, between Gran Tierra Energy Inc., Gran Tierra Exchangeco Inc. and Computershare Trust Company of Canada.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on November 17, 2008 (SEC File No. 001-34018).

10.3	Support Agreement, dated as of November 14, 2008, between Gran Tierra Energy Inc., Gran Tierra Callco ULC and Gran Tierra Exchangeco Inc.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on November 17, 2008 (SEC File No. 001-34018).

10.4	Share Purchase Agreement dated as of June 30, 2016, among Gran Tierra Energy International Holdings Ltd., Tribeca Oil & Gas Inc., Macquarie Bank Limited, Rorick Ventures Group Inc., as vendors, and PetroLatina Energy Limited.	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on July 7, 2016 (SEC File No. 001-34018).

10.5	Share and Loan Purchase Agreement, dated February 5, 2017, by Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S. Á. R.L. and Maha Energy AB	Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the SEC on July 6, 2017 (SEC File No. 001-34018).

10.6	Amendment #1, dated May 30, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed with the SEC on July 6, 2017 (SEC File No. 001-34018).

10.7	Amendment #2, dated June 22, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K filed with the SEC on July 6, 2017 (SEC File No. 001-34018).

10.8	Amendment #3, dated June 26, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K filed with the SEC on July 6, 2017 (SEC File No. 001-34018).

10.9	Amendment #4, dated August 31, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the SEC on November 2, 2017 (SEC File No. 001-34018).



10.10	Amendment #5, dated October 26, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Filed herewith.

10.11	Amendment #6, dated November 8, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Filed herewith.

10.12	Amendment #7, dated November 17, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.	Filed herewith.

10.13	Amended and Restated 2007 Equity Incentive Plan. *	Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed with the SEC on August 7, 2012 (SEC File No. 001-34018).

10.14	Form of Restricted Stock Unit Award Agreement Under the 2007 Equity Incentive Plan. *	Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on August 7, 2013 (SEC File No. 001-34018).

10.15	Form of Option Agreement Under the 2007 Equity Incentive Plan. *	Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the SEC on August 7, 2013 (SEC File No. 001-34018).

10.16	Form of Indemnity Agreement. *	Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed with the SEC on April 2, 2008 (SEC File No. 000-52594).

10.17	Executive Employment Agreement, dated January 20, 2010, between Gran Tierra Energy Inc. and David Hardy. *	Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed with the SEC on May 10, 2011 (SEC File No. 001-34018).

10.18	Amendment to Employment Agreement dated May 2, 2012, between Gran Tierra Energy Inc. and David Hardy. *	Incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).

10.19	Employment Agreement dated July 31, 2014, between Gran Tierra Energy Colombia Ltd. and Adrián Santiago Coral Pantoja. *	Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, filed with the SEC on August 7, 2014 (SEC File No. 001-34018).

10.20	Amendment No. 2 to Executive Employment Agreement dated May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and David Hardy.*	Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2015 (SEC File No. 001-34018).

10.21	Form of Indemnity Agreement for use with Directors and Executive Officers.*	Incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2015 (SEC File No. 001-34018).

10.22	Form of Deferred Stock Unit Award Agreement Under the 2007 Equity Incentive Plan.*	Incorporated by reference to Exhibit 10.29 to the Annual Report on Form 10-K, filed with the SEC on February 29, 2016 (SEC File No. 001-34018).

10.23	Form of Deferred Stock Unit Grant Notice.*	Incorporated by reference to Exhibit 10.30 to the Annual Report on Form 10-K, filed with the SEC on February 29, 2016 (SEC File No. 001-34018).

10.24	Executive Employment Agreement effective May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Gary Guidry.*	Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2015 (SEC File No. 001-34018).



10.25	Executive Employment Agreement effective May 11 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Lawrence West.*	Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2015 (SEC File No. 001-34018).

10.26	Executive Employment Agreement effective May 11, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and James Evans.*	Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2015 (SEC File No. 001-34018).

10.27	Form of Performance Stock Unit Award Agreement Under the 2007 Equity Incentive Plan.*	Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2016 (SEC File No. 001-34018).

10.28	Form of Performance Stock Unit Grant Notice.*	Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2016 (SEC File No. 001-34018).

10.29	Executive Employment Agreement effective May 11 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Ryan Ellson.*	Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2016 (SEC File No. 001-34018).

10.30	Credit Agreement, dated as of September 18, 2015, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2015 (SEC File No. 001-34018).

10.31	First Amendment to Credit Agreement, dated as of March 31, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).

10.32	Second Amendment to Credit Agreement, dated as of June 2, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on June 3, 2016 (SEC File No. 34018).

10.33	Third Amendment to Credit Agreement, dated as of August 23, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.	Incorporated by reference to Exhibit 10.42 to the Annual Report on Form 10-K, filed with the SEC on March 1, 2017 (SEC File No. 001-34018).

10.34	Fourth Amendment to Credit Agreement, dated as of November 16, 2016, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.43 to the Annual Report on Form 10-K, filed with the SEC on March 1, 2017 (SEC File No. 001-34018).

10.35	Fifth Amendment to Credit Agreement, dated as of February 13, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on February 15, 2017 (SEC File No. 001-34018).

10.36	Sixth Amendment to Credit Agreement, dated May 17, 2017 and effective as of June 1, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on May 19, 2017 (SEC File No. 001-34018).

10.37	Seventh Amendment to Credit Agreement, dated as of June 15, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, filed with the SEC on August 4, 2017 (SEC File No. 001-34018).



10.38	Eighth Amendment to Credit Agreement, dated as of September 18, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2017 (SEC File No. 001-34018).

10.39	Ninth Amendment to Credit Agreement, dated as of November 10, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on November 14, 2017 (SEC File No. 001-34018).

10.40	Colombian Participation Agreement, dated as of June 22, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.55 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008 (SEC File No. 001-34018).

10.41	Amendment No. 1 to Colombian Participation Agreement, dated as of November 1, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.56 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008 (SEC File No. 001-34018).

10.42	Amendment No. 2 to Colombian Participation Agreement, dated as of July 3, 2008, between Gran Tierra Energy Inc. and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q/A, filed with the SEC on November 19, 2008 (SEC File No. 001-34018).

10.43	Amendment No. 3 to Participation Agreement, dated as of December 31, 2008, by and among Gran Tierra Energy Colombia, Ltd., Gran Tierra Energy Inc. and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009 (SEC File No. 001-34018).

10.44	Amendment No. 4 dated June 13, 2011, to the Colombian Participation Agreement dated June 22, 2006, between Gran Tierra Colombia Ltd and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).

10.45	Amendment No. 5 dated February 10, 2011, to the Colombian Participation Agreement dated June 22, 2006, between Gran Tierra Colombia Ltd and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).

10.46	Amendment No. 6 dated March 1, 2012, to the Colombian Participation Agreement dated June 22, 2006, between Gran Tierra Colombia Ltd and Crosby Capital, LLC.	Incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).

12.1	Statement re: Computation of Ratio of Earnings to Fixed Charges.	Filed herewith.

21.1	List of subsidiaries.	Filed herewith.

23.1	Consent of Deloitte LLP.	Filed herewith.

23.2	Consent of McDaniel & Associates Consultants Ltd.	Filed herewith.

24.1	Power of Attorney.	See signature page.

31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	Filed herewith.

31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	Filed herewith.

100



32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	Furnished herewith.

99.1	Gran Tierra Energy Inc. Reserves Assessment and Evaluation of Oil and Gas Properties Corporate Summary, effective December 31, 2017.	Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-k, filed with the SEC on January 31, 2018 (SEC File No. 001-34018).

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

* Management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

GRAN TIERRA ENERGY INC.



Date: February 27, 2018		/s/ Gary S. Guidry
		By: Gary S. Guidry
		President and Chief Executive Officer, Director
		(Principal Executive Officer)



Date: February 27, 2018		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

101

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Gary S. Guidry and Ryan Ellson, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:



Name	Title	Date

/s/ Gary S. Guidry	President and Chief Executive Officer, Director	February 27, 2018
Gary S. Guidry	(Principal Executive Officer)

/s/ Ryan Ellson	Chief Financial Officer	February 27, 2018
Ryan Ellson	(Principal Financial and Accounting Officer)

/s/ Peter Dey	Director	February 27, 2018
Peter Dey

/s/ Evan Hazell	Director	February 27, 2018
Evan Hazell

/s/ Robert B. Hodgins	Director	February 27, 2018
Robert B. Hodgins

/s/ Ronald Royal	Director	February 27, 2018
Ronald Royal

/s/ Sondra Scott	Director	February 27, 2018
Sondra Scott

/s/ David P. Smith	Director	February 27, 2018
David P. Smith

/s/ Brooke Wade	Director	February 27, 2018
Brooke Wade

102