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~~2019



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~~
	Calgary,	Alberta	Canada	T2P 0R3
(Address of principal executive offices, including zip code)

~~(403)~~

(403) 265-3221

(Registrant’s telephone number, including area code)

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



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.001 per share	GTE	NYSE American
			Toronto Stock Exchange
		London 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 o No 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 companyo	☐
		Emerging growth companyo	☐

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,~~2019, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $~~0.9~~0.5 billion.

On February ~~22, 2018, the following numbers of shares of the registrant’s capital stock were outstanding: 385,394,642~~24, 2020, 366,981,556 shares of the registrant’s Common Stock ~~$0.001 par value; one share of Special A Voting Stock,~~with $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.were outstanding.

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~~2020 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, ~~2017~~.

2019.

Gran Tierra Energy Inc.

Annual Report on Form 10-K

Year EndedDecember 31, ~~2017~~2019

Table of Contents



		Page

PART I
Items 1 and 2.	Business and Properties	5
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	2324
Item 3.	Legal Proceedings	2324
Item 4.	Mine Safety Disclosures	2324

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	2827
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	3129
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	5449
Item 8.	Financial Statements and Supplementary Data	5550
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	9183
Item 9A.	Controls and Procedures	9284
Item 9B.	Other Information	9486

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	9486
Item 11.	Executive Compensation	9486
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	9486
Item 13.	Certain Relationships and Related Transactions, and Director Independence	9587
Item 14.	Principal Accounting Fees and Services	9587

PART IV
Item 15.	Exhibits, Financial Statement Schedules	9587
Item 16.	Form 10-K Summary	~~101~~93

SIGNATURES		~~101~~93

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~~NAR	~~natural gas liquids~~net after royalty
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.~~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)~~("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)~~("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”, “the Company”, “us”, “our”, or “we”), is a company focused on oil and gas exploration and production in ~~Colombia.~~Colombia and Ecuador. Our Colombian properties represented 100% of our proved reserves NAR at December 31, ~~2017.~~2019. For the year ended December 31, ~~2017, 98%~~2019, 100% (year ended December 31, ~~2016~~2018 - ~~97%;~~100%, and year ended December 31, ~~2015~~2017 - ~~97%~~98%) of our revenue and other income was generated in Colombia.

We ~~made~~were incorporated under the laws of the State of Nevada in June 2008 and changed our ~~initial acquisition~~state of ~~oil and gas producing and non-producing properties~~incorporation to the State of Delaware 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.October 2016.

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

~~2017~~2019 Overview

Acquisitions and Dispositions

On ~~April 27, 2017,~~February 20, 2019, we acquired ~~an operated 100%~~36.2% working interest ~~(“WI”~~("WI") and operatorship in the ~~Santana~~Suroriente Block and ~~Nancy-Burdine-Maxine Blocks~~100% WI in the ~~Putumayo Basin in Colombia~~Llanos-5 Block for a cash consideration of ~~$30.4~~$79.1 million and a promissory note of $1.5 million. The acquisition increased our WI in Suroriente Block from 16% to 52%. As of December 31, 2019, the Suroriente Block had 6,084 MBOE of proven reserves and 10,390 MBOE of proven plus probable reserves.

On ~~June 30, 2017,~~May 22, 2019, we ~~completed~~signed participation contracts for the ~~sale of~~Charapa, Chanangue and Iguana Blocks located in the Oriente Basin in Ecuador and secured 100% WI and operatorship for these blocks. We expect to commence our ~~Brazil business unit for~~exploration drilling program in Ecuador during 2020. The blocks added 138,239 acres in a ~~purchase price of $35.0 million, which, after certain final closing adjustments, resulted in cash consideration of approximately $36.8 million.~~ highly prospective basin with access to infrastructure.

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~~

InDuring the year ended December 31, ~~2017,~~2019, we were awarded four exploration blocks (PUT-21, PUT-33, Llanos-85 and VMM-24) via successful bid rounds in Colombia. The newly awarded blocks added 286,729 acres in highly prospective basins in Colombia, all with access to infrastructure.

2019 Operational Highlights

During the year ended December 31, 2019, we incurred capital expenditures of ~~$251.0~~$379.3 million, ~~including $242.6 million, or 97%,~~the majority of which were incurred in Colombia. In ~~Colombia,~~2019, we drilled ~~4 exploration and 21 development wells, including 2 service wells.~~

~~We drilled~~six exploration wells, ~~in the Putumayo-1 Block (Vonu-1), Putumayo-7 Block (Confianza-1), Putumayo-4 Block (Siriri-1)~~five water injectors, 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.~~25 development wells.

~~Development~~The six exploration wells were drilled in the ~~Midas Block (Acordionero-9, 10i, 11, 12, 13, 14i, 15, 16, 17, 18, 20, 21~~PUT-1, PUT-7, El Porton, Llanos-10 and ~~Mochuelo), Suroriente Block (Cohembi-19, 20, 21, 22), Chaza Block (Costayaco-28, 29 and 30) and Guayuyaco Block (Juanambu-2). Two~~Santana Blocks. As at December 31, 2019, three of these wells were ~~water injection wells (Acordionero-10i~~producing, two were in-progress and ~~14i).~~one was a dry well.

We ~~acquired and processed new 3-D seismic~~spud five water injector wells, all in the ~~Cumplidor and Northwest areas~~Midas Block.

We spud 25 development wells; 19 in the ~~Putumayo-7~~Midas Block, three in the VMM-2 Block and three in the Chaza Block. ~~Two walkaway vertical seismic profiles~~As at December 31, 2019, 22 of these wells were ~~acquired~~producing, two did not achieve economic rates and ~~processed~~one was in-progress.

Of the seven wells in-progress in Colombia as at December 31, 2018, three were producing, three were dry and one remained in-progress as at December 31, 2019.

During 2019, we commissioned facilities in the Acordionero ~~Field. We re-processed 2-D~~Field and ~~3-D seismic~~continued other facilities work in the ~~Llanos Basin (Garibay-El Porton area), Middle Magdalena Basin (Acordionero, Los Angeles, Midas Norte areas)~~Moqueta 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~~Costayaco Fields on the Chaza Block.

~~2018~~

2020 Outlook

Colombia remains our primary focus and represents ~~100%~~97% of our 2020 capital program with the ~~2018~~remainder allocated to exploration activities in Ecuador.

The table below shows break-down of our 2020 capital ~~program. In December 2017, we announced our 2018 capital budget. We expect the following ranges for our 2018 capital budget:~~

program:



	Number of Wells (Gross)	Number of Wells (Net)	~~2018~~2020 Capital Budget ($ million)
Colombia
Development	~~19-21~~16-19	15-18	~~18-20~~	~~100-105~~	140-160
Exploration	~~8-11~~1-2	1-2	~~7-10~~25-35
Ecuador		~~80-90~~
~~Facilities~~Exploration	—0-1	0-1	—	~~50-55~~	0-10
~~Seismic and Studies~~	—17-22	16-21	—	20
	~~27-32~~		~~25-30~~	~~250-270~~	175-195⁽¹⁾

⁽¹⁾ Assumes the mid-point of budgeted amount for exploration

Based on the ~~midpoint~~mid-point of the 2020 guidance, the capital budget is forecasted to be approximately ~~60%~~80% directed to development and ~~40%~~20% to exploration. ~~Between 30% and 35%~~Approximately 20% of the ~~2018~~development activities included in the 2020 capital program isare 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.~~facilities.

We expect our ~~2018~~2020 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.~~Colombia and Ecuador in a sustainable manner. 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~~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.~~operations.

Oil and Gas Properties - Colombia and Ecuador

Acquisitions ~~and Farm-ins~~

On ~~April 27, 2017,~~February 20, 2019, we acquired ~~an operated~~36.2% WI and operatorship in the Suroriente Block and 100% WI in the ~~Santana and Nancy-Burdine-Maxine Blocks in the Putumayo Basin~~Llanos-5 Block for a cash consideration of ~~$30.4~~$79.1 million and a promissory note of $1.5 million. The acquisition increased our WI in Suroriente Block from 16% to 52%.

On May 22, 2019, we signed participation contracts for the Charapa, Chanangue and Iguana Blocks located in the Oriente Basin in Ecuador and secured 100% WI and operatorship for these blocks. We expect to commence our exploration drilling program in Ecuador during 2020.

~~On November 27, 2017,~~

During the year ended December 31, 2019, we ~~entered into two farm-in agreements to acquire, subject to approval from the Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”), additional WIs~~were awarded four exploration blocks (PUT-21, PUT-33, Llanos-85 and VMM-24) via successful bid rounds 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.Colombia.

Excluding blocks subject to relinquishment, we have interests in 3029 blocks in Colombia, three blocks in Ecuador and are the operator on 2329 of ~~these~~those blocks.

Exploration Blocks & Commitments

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

2019:



Basin	Block	Current Phase	Remaining Commitments, Current Phase
Colombia
Putumayo	Alea 1848-A	3 & 4	~~70 km 2D seismic,~~ 1 exploration well
Putumayo	Alea 1947-C	2*	1 exploration well
Putumayo	~~PPN~~Chaza E&P	1*Production	~~52 km 2D seismic~~
~~Putumayo~~	~~PPS~~	2 & 3*	~~2 km of 2D seismic,~~ 1 exploration well
Putumayo	PUT-1	22*	2 exploration wells
Putumayo	PUT-2	22**	3 exploration wells
Putumayo	PUT-4	1	1 exploration well
Putumayo	PUT-7	12	12 exploration ~~well~~wells
Putumayo	PUT-10	1*	73 km 2D seismic, 2 exploration wells
~~Llanos~~Putumayo	~~El Porton~~PUT-25	5*1	1 exploration well
Putumayo	PUT-31	1	200 km² 3D seismic,1.9 km 2D seismic,1 exploration well
Llanos	LLA-1	1**	97.5 km² 3D seismic, 1 exploration well
Llanos	~~LLA-10~~LLA-5	1**	133 km² 3D seismic, 1 exploration well
Llanos	LLA-22	1 & 2*	85 km² 3D seismic, 1 exploration well
~~Llanos~~	~~LLA-53~~	1*	~~89 km~~² ~~3D seismic, 2 exploration wells (approval requested to transfer commitments to PUT4- and PUT-7)~~
Llanos	LLA-70	1**	~~163~~163.4 km² 3D seismic, 1 exploration well
Llanos	LLA-85	1	50 km² 3D seismic, 451 km² 3D seismic reprocessing
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)~~Ecuador
~~Sinú~~Oriente	~~SN-3~~Charapa	1	150 km 2D seismic, 172 points of surface geochemistry, 7 exploration ~~well, including vertical~~wells
Oriente	Chanangue	1	Reprocess 190 km² 3D seismic, ~~program and biostratigraphy studies~~155 points surface geochemistry, 5 exploration wells
Oriente	Iguana	1	Reprocess 201 km² 3D seismic, 2 exploration wells

*As of February ~~22, 2018,~~24, 2020, suspended due to either licensing restrictions or social reasons

** As of February ~~22, 2018,~~24, 2020, 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~~Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“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~~These royalties work 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~~bopd, 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%. The Santana and Nancy-Burdine-Maxine Blocks have a fixed rate for existing production of 32% and 20%, respectively, and sliding scale for new discoveries or incremental production duly approved by ANH. 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, VMM-2 and Llanos-10: 3%; Putumayo-1: 5%; 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.~~

Llanos-1, Llanos -70: 31%; Llanos-53: 33%.

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%~~16% for gross production between 28.5 MMcf of gas per day and ~~3.42 Bcf~~712.5 MMcf of gas per day and is stable at 16% for gross production between 712.5 to 2,280 MMcf of gas per ~~day. For~~day, and then increases in a linear fashion from 16% to 20% 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%.~~day. 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,~~2019, 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~~and Putumayo 1 Blocks are also subject to a third party royalty in addition to the government royalties. Putumayo-7: 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’~~'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~~ Pursuant to the ~~sale~~terms 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~~agreement by which the interests in the ~~Recôncavo Basin in Eastern Brazil in~~Putumayo-1 Block were acquired, a 3% royalty on production from the ~~State~~Putumayo-1 Block is payable to a third party. The terms of ~~Bahia.~~

~~Until December 18, 2017, we had a 100% WI in five blocks in Peru~~the royalty do not allow for any costs, royalties 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.

taxes to be deducted from production revenue.

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.~~Colombia and Ecuador.

Estimated Reserves

Our ~~2017~~2019 reserves were independently prepared by McDaniel International Inc. (“McDaniel”), a ~~wholly owned~~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.~~Chief Operating Officer. He has a ~~B. Eng (Hons)~~Bachelor of Science degree in ~~mechanical engineering~~Geological Engineering from the University of Saskatchewan 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~~multi-disciplinary upstream oil and gas ~~industry.~~experience and eight years of executive level leadership experience including leadership project management roles in international oil and gas companies.

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. The probable reserves that have been assigned as of December 31, 2019 were based on both the greater percentage of recovery of the hydrocarbons in place than assumed for proved reserves, as well as to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain.

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 possible reserves that have been assigned as of December 31, 2019 were based on both the greater percentage of recovery of the hydrocarbons

in place than assumed for probable reserves as well as to areas of a reservoir adjacent to probable reserves where data control or interpretations of available data are less certain.

The following table sets forth our estimated reserves NAR as of December 31, ~~2017.~~2019:


	Oil	Natural Gas	Oil and Natural Gas	Oil	Natural Gas	Oil and Natural Gas
Reserves Category	(Mbbl)	(MMcf)	(MBOE)	(Mbbl)	(MMcf)	(MBOE)
Proved

Total proved developed reserves	39,487	1,431	39,726	36,465	1,008	36,633
Total proved undeveloped reserves	19,467	653	19,576	30,864	886	31,012
Total proved reserves	58,954	2,084	59,302	67,329	1,894	67,645

Probable
Probable ⁽¹⁾
Total probable developed reserves	13,499	307	13,550	19,896	339	19,953
Total probable undeveloped reserves	41,442	1,311	41,661	38,259	992	38,424
Total probable reserves	54,941	1,618	55,211	58,155	1,331	58,377

Possible
Possible ⁽¹⁾
Total possible developed reserves	16,893	320	16,946	21,368	460	21,445
Total possible undeveloped reserves	40,955	1,312	41,174	16,351	1,019	16,521
Total possible reserves	57,848	1,632	58,120	37,719	1,479	37,966

⁽¹⁾Estimates of probable and possible reserves are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty. Accordingly, estimates of probable and possible reserves are not comparable and have not been, or should not be, summed arithmetically with each other or with estimates of proved reserves.

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
Oil ($/bbl) - Colombia			$	54.05
Natural Gas ($/Mcf) - Colombia	$	3.67	$	3.67
ICE Brent - average of the first day of each month price for the 12-month period	$	54.19	$	64.20

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.~~prices. 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~~,2019, we had total proved undeveloped reserves NAR of ~~19.6~~31.0 MMBOE (~~December~~(December 31, ~~2016~~2018 - ~~14.9~~17.3 MMBOE), which were 100% in Colombia (~~December~~(December 31, ~~2016~~2018 – ~~70%)~~100% in Colombia). Approximately ~~64%~~59%, ~~13%~~ 11%, 8% and 10% ~~and 7%~~for a total of 88% of proved undeveloped reserves are located in our Acordionero, Cohembi, Costayaco ~~Cumplidor~~ and Moqueta Fields, respectively, in Colombia. None of our proved undeveloped reserves at December 31, ~~2017~~2019 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~~Changes in proved undeveloped reserves during the year ended December 31, 2019 are ~~summarized~~shown 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



	Colombia - Oil Equivalent (MMBOE)
Balance, December 31, 2018	17.3
Acquisitions	1.5
Converted to proved producing	(8.7	)
Extensions	6.1
Technical revisions	14.8
Balance, December 31, 2019	31.0

In ~~2017,~~2019, we converted ~~5.3~~8.7 MMBOE, or ~~51%~~50%, of ~~2016 Colombian~~2018 proved undeveloped reserves to developed status. In ~~2017,~~2019, we made investments, consisting solely of capital expenditures, of ~~$62.8~~$81.3 million in Colombia associated with the development of proved undeveloped reserves.

Changes in proved undeveloped reserves during the year ended December 31, 2019 shown in the table above primarily resulted from the following significant factors:

Acquisitions. During the year ended December 31, 2019, we added 1.5 MMBOE of proved undeveloped reserves as a result of acquisitions of 36.2% WI in the Suroriente Block and 20% WI in the VMM-2 Block.

Converted to Proved Producing. In 2019, we converted 8.7 MMBOE, or 50% of 2018 proved undeveloped reserves to developed status. This was based on drilling 15 wells in the Midas Block, three wells in the Chaza Block and two wells in the PUT-7 Block.

Extensions. Extensions added 6.1 MMBOE of 2019 proved undeveloped reserves during the year ended December 31, 2019 and were attributed to extensions of 4.9 MMBOE in the Acordionero field and 1.2 MMBOE in the Costayaco field.

Technical Revisions. During the year ended December 31, 2019, we experienced revisions of 14.8 MMBOE of 2019 proved undeveloped reserves to proved developed reserves, primarily as a result of positive technical revisions based on well performance in the Acordionero and Cohembi Fields.

Production, Revenue and Price History

Certain information concerning production, prices, revenues and operating expenses for the three years ended December 31, ~~2017~~2019 is set forth in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the ~~Unaudited~~“Unaudited Supplementary ~~Data~~Data” provided following our Financial Statements in Item 8, which information is incorporated by reference here.

The following table presents NAR oil production, average sales prices and ~~NGL~~operating expenses per NAR oil production ~~NAR~~ from our major Fields Costayaco, Moqueta, Cohembi and Acordionero ~~Fields~~and from all of our properties for each of the three years ended December 31, ~~2017~~:2019:

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



	Costayaco⁽¹⁾		Moqueta⁽¹⁾		Cohembi⁽¹⁾		Acordionero⁽¹⁾		Total for all properties^{(2) (3)}
	Year Ended December 31, 2019
Oil production NAR bbl	1,966,585		1,022,391		675,086		5,166,430		10,590,137
Average sales price of oil per bbl	$	56.38	$	55.93	$	54.35	$	54.17	$	53.92
Operating expenses of oil per bbl ⁽⁴⁾	$	18.95	$	18.88	$	23.94	$	14.60	$	19.23
	Year Ended December 31, 2018
Oil production NAR bbl	2,244,497		1,020,673		324,798		5,469,072		10,604,197
Average sales price of oil per bbl	$	58.19	$	59.87	$	55.06	$	57.64	$	57.85
Operating expenses of oil per bbl ⁽⁴⁾	$	22.23	$	20.47	$	22.81	$	11.22	$	16.47
	Year Ended December 31, 2017
Oil production NAR bbl	3,173,659		1,550,344		251,618		3,131,577		9,776,533
Average sales price of oil per bbl	$	43.55	$	45.05	$	37.55	$	43.90	$	43.14
Operating expenses of oil per bbl ⁽⁴⁾	$	11.70	$	15.27	$	24.30	$	10.34	$	13.81

⁽¹⁾ 100% of product sales were oil

⁽²⁾ Includes de minimis natural gas sales from non-core properties from Colombia of 361,065 mcf (60,178 boe), 208,961 mcf (34,827 boe) and 591,775 mcf (98,629 boe) for each of the years ended December 31, 2019, 2018 and 2017, respectively

⁽³⁾ In 2019 and 2018, 100% of production was from Colombia and in 2017 total production from all properties included oil and natural gas production from Brazil of 197,841 bbl of oil and 73,325 mcf (12,221 boe) of natural gas

⁽⁴⁾Operating expenses include lifting, workover and transportation

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~~2019, 2018 or ~~2015.~~2017. 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		2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Colombia

Exploration
Productive	2.00	1.55	2.00	2.00	—	—	3.00	2.50	1.00	1.00	2.00	1.55
Dry	—	—	—	—	1.00	1.00	1.00	1.00	1.00	0.51	—	—
In Progress	2.00	2.00	1.00	1.00	—	—	2.00	2.00	3.00	3.00	2.00	2.00
Development
Productive	17.00	13.63	7.00	7.00	7.00	5.16	22.00	22.00	19.00	18.16	17.00	13.63
Service	2.00	2.00	2.00	2.00	—	—
Dry	—	—	1.00	1.00	—	—	2.00	2.00	—	—	—	—
In Progress	2.00	1.70	3.00	3.00	6.00	6.00	1.00	1.00	4.00	4.00	2.00	1.70
Service
Water injectors							5.00	5.00	—	—	2.00	2.00
Total Colombia	25.00	20.88	16.00	16.00	14.00	12.16	36.00	35.50	28.00	26.67	25.00	20.88

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

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



	Year Ended December 31,
	2019			2018		2017
OIL AND NATURAL GAS SALES (NOTE 9)	$	570,983		$	613,431	$	421,734

EXPENSES
Operating	142,086			111,272		87,855
Workover	41,118			34,437		22,014
Transportation	20,400			28,993		25,107
Depletion, depreciation and accretion (Note 5)	225,033			197,867		131,335
Asset impairment (Note 5)	—			—		1,514
General and administrative	34,730			39,483		39,014
Severance	1,771			2,361		1,287
Equity tax	—			—		1,224
Foreign exchange loss	627			9,957		2,067
Financial instruments (gain) loss (Note 13)	(46,215		)	12,296		15,929
Interest expense (Note 6)	43,268			27,364		13,882
TOTAL EXPENSES	462,818			464,030		341,228

OTHER LOSS (Notes 5, 6 and 10)	(12,886		)	—		(44,385		)
INTEREST INCOME	696			2,086		1,209
INCOME BEFORE INCOME TAXES	95,975			151,487		37,330

INCOME TAX EXPENSE
Current (Note 10)	17,058			43,903		24,322
Deferred (Note 10)	40,227			4,968		44,716
	57,285			48,871		69,038
NET AND COMPREHENSIVE INCOME (LOSS)	$	38,690		$	102,616	$	(31,708	)

NET INCOME (LOSS) PER SHARE
– BASIC	$	0.10		$	0.26	$	(0.08	)
– DILUTED	$	0.10		$	0.26	$	(0.08	)
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 7)	376,495,306			390,930,453		396,683,593
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 7)	376,507,812			427,119,872		396,683,593

(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,						As at December 31,
	2017			2016			2019			2018
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
Cash and cash equivalents							$	8,301		$	51,040
Restricted cash and cash equivalents (Note 8)							516			1,269
Accounts receivable (Note 4)	45,353			45,698			36,291			26,177
Investment (Note 12)	25,055			—
Derivatives (Note 12)	302			578
Inventory	7,075			7,766
Investment (Note 13)							94,741			32,724
Taxes receivable	40,831			26,393			135,838			78,259
Prepaid taxes (Notes 2 and 9)	—			12,271
Other prepaids	2,516			5,482
Other current assets							15,001			13,056
Total Current Assets	145,245			131,685			290,688			202,525

Oil and Gas Properties (using the full cost method of accounting)
Proved	629,081			412,319			1,258,934			853,428
Unproved	464,948			647,774			310,809			456,598
Total Oil and Gas Properties	1,094,029			1,060,093			1,569,743			1,310,026
Other capital assets	5,195			6,516			7,650			2,751
Total Property, Plant and Equipment (Notes 3 and 5)	1,099,224			1,066,609
Total Property, Plant and Equipment (Notes 5)							1,577,393			1,312,777

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
Taxes receivable							25,869			—
Deferred tax assets (Note 10)							44,003			45,437
Investment (Note 13)							—			8,711
Other long-term assets							4,130			4,553
Goodwill							102,581			102,581
Total Other Long-Term Assets	185,150			169,602			176,583			161,282
Total Assets (Note 3)	$	1,429,619		$	1,367,896
Total Assets							$	2,044,664		$	1,676,584

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
Accounts payable and accrued liabilities (Note 11)							$	195,513		$	154,670
Derivatives (Note 13)							775			1,017
Taxes payable							—			4,149
Equity compensation award liability (Note 7 and 13)							3,053			9,544
Total Current Liabilities	156,969			155,029			199,341			169,380

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
Long-term debt (Notes 6)							700,459			399,415
Deferred tax liabilities (Note 10)							59,762			23,419
Asset retirement obligation (Note 8)	31,241			38,142			43,419			43,676
Equity compensation award liability (Note 7 and 13)							4,806			8,139
Other long-term liabilities	20,115			11,425			4,267			2,805
Total Long-Term Liabilities	336,315			353,880			812,713			477,454

Commitments and Contingencies (Note 11)
Subsequent Event (Note 14)
Commitments and Contingencies (Note 12)

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
Common Stock (Note 7) (366,981,556 and 387,079,027 shares of Common Stock, par value $0.001 per share, issued and outstanding as at December 31, 2019 and December 31, 2018, respectively)							10,270			10,290
Additional paid in capital	1,327,244			1,342,656			1,282,627			1,318,048
Deficit	(401,204		)	(493,972		)	(260,287		)	(298,588		)
Total Shareholders’ Equity	936,335			858,987			1,032,610			1,029,750
Total Liabilities and Shareholders’ Equity	$	1,429,619		$	1,367,896		$	2,044,664		$	1,676,584

(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)



	Year Ended December 31,
	2019			2018			2017
Operating Activities
Net income (loss)	$	38,690		$	102,616		$	(31,708	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion (Note 5)	225,033			197,867			131,335
Asset impairment (Note 5)	—			—			1,514
Deferred tax expense (Note 10)	40,227			4,968			44,716
Stock-based compensation (Note 7)	1,430			8,299			9,775
Amortization of debt issuance costs (Note 6)	3,376			3,183			2,415
Non-cash lease expenses	1,806			—			—
Lease payments	(1,969		)	—			—
Cash settlement of restricted share units	—			(360		)	(564		)
Unrealized foreign exchange loss	1,803			11,511			837
Financial instruments (gain) loss (Note 13)	(46,215		)	12,296			15,929
Cash settlement of financial instruments	(3,273		)	(33,931		)	1,563
Cash settlement of asset retirement obligation (Note 8)	(870		)	(519		)	(1,336		)
Loss on sale (Note 5)	—			—			44,385
Loss on redemption of Convertible Notes (Note 6)	11,501			—			—
Net change in assets and liabilities from operating activities (Note 14)	(93,874		)	(21,421		)	(29,217		)
Net cash provided by operating activities	177,665			284,509			189,644

Investing Activities
Additions to property, plant and equipment (Note 5)	(379,314		)	(347,093		)	(251,041		)
Property acquisitions (Note 5)	(77,772		)	(53,200		)	(34,410		)
Net proceeds from sale of business units	—			—			32,968
Cash paid for investments	—			—			(11,000		)
Changes in non-cash investing working capital	(7,851		)	17,704			19,680
Net cash used in investing activities	(464,937		)	(382,589		)	(243,803		)

Financing Activities
Proceeds from issuance of Senior Notes, net of issuance costs (Note 6)	289,271			288,131			—
Proceeds from bank debt, net of issuance costs	342,575			4,560			167,043
Repayment of debt	(349,219		)	(153,000		)	(110,000		)
Proceeds from exercise of stock options	—			1,429			—
Repurchase of shares of Common Stock (Note 7)	(37,561		)	(12,742		)	(17,916		)
Net cash provided by financing activities	245,066			128,378			39,127

Foreign exchange loss on cash, cash equivalents and restricted cash and cash equivalents	(1,027		)	(2,668		)	(1,557		)

Net (decrease) increase in cash, cash equivalents and restricted cash and cash equivalents	(43,233		)	27,630			(16,589		)
Cash and cash equivalents and restricted cash and cash equivalents, beginning of year (Note 14)	54,308			26,678			43,267
Cash and cash equivalents and restricted cash and cash equivalents, end of year (Note 14)	$	11,075		$	54,308		$	26,678

Supplemental cash flow disclosures (Note 14)

(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,									Year Ended December 31,
	2017			2016			2015			2019			2018			2017
Share Capital
Balance, beginning of year	$	10,303		$	10,186		$	10,190		$	10,290		$	10,295		$	10,303
Issuance of Common Stock (Note 7)	—			117			—
Repurchase of Common Stock (Note 7)	(8		)	—			(4		)	(20		)	(5		)	(8		)
Balance, end of year	10,295			10,303			10,186			10,270			10,290			10,295

Additional Paid in Capital
Balance, beginning of year	1,342,656			1,019,863			1,026,873			1,318,048			1,327,244			1,342,656
Issuance of Common Stock, net of share issuance costs (Note 7)	—			314,425			—
Exercise of stock options (Note 7)	—			5,347			722			—			1,429			—
Stock-based compensation (Note 7)	2,496			3,021			2,263			2,120			2,112			2,496
Repurchase of Common Stock (Note 7)	(17,908		)	—			(9,995		)	(37,541		)	(12,737		)	(17,908		)
Balance, end of year	1,327,244			1,342,656			1,019,863			1,282,627			1,318,048			1,327,244

(Deficit) Retained Earnings
Deficit
Balance, beginning of year	(493,972		)	(28,407		)	239,622			(298,588		)	(401,204		)	(493,972		)
Net loss	(31,708		)	(465,565		)	(268,029		)
Cumulative adjustment for accounting changes related to tax reorganizations (Note 2)	124,476			—			—
Net income (loss)										38,690			102,616			(31,708		)
Cumulative adjustment for accounting changes related to leases and tax reorganizations (Note 2)										(389		)	—			124,476
Balance, end of year	(401,204		)	(493,972		)	(28,407		)	(260,287		)	(298,588		)	(401,204		)

Total Shareholders’ Equity	$	936,335		$	858,987		$	1,001,642		$	1,032,610		$	1,029,750		$	936,335

(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~~2019, 2018 and ~~2015~~2017

(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,~~Colombia and ~~in Peru until December 18, 2017.~~Ecuador.

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~~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~~.

Investment in PetroTal Corp.

~~Equity method investment~~

During December 2017, the Company acquired an investment in common shares of ~~Sterling~~PetroTal Corp. ("PetroTal") in connection with the sale of its Peru business ~~unit (Note 5).~~unit. At December 31, ~~2017,~~2019, this investment represented approximately ~~46%~~37% of ~~Sterling's~~PetroTal's issued

and outstanding common shares. The Company determined that it did not have a controlling financial interest in ~~Sterling,~~PetroTal, but could exert significant influence over ~~Sterling's~~PetroTal's operating and financial policies as a result of its ownership interest in ~~Sterling~~PetroTal and the right to nominate ~~two~~2 directors to ~~Sterling's~~PetroTal's board of directors. Accordingly, Gran Tierra accounted for its investment in the common shares of ~~Sterling~~PetroTal 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~~PetroTal's common shares is recorded in 'Investments' in the consolidated balance sheet, and the change in fair value is recorded in the consolidated ~~statement~~statements 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~~statements 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.

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~~Oil and ~~Cash Equivalents~~gas properties

~~In November 2016,~~

The Company computes depletion of oil and natural gas properties on a quarterly basis using the ~~FASB issued ASU 2016-18, "Restricted Cash". ASU 2016-18 requires~~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 ~~statement~~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 ~~explain~~from proved oil and natural gas reserves discounted at 10%, net of related tax effects, plus the ~~change during~~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.

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

Gains and losses on the sale or ~~restricted cash equivalents. ASU 2016-18 is effective for annual reporting periods~~other disposition of oil and ~~interim reporting periods within those annual reporting periods, beginning after December 15, 2017. Early adoption was permitted.~~ 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 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, comparedrecords an estimated liability for future costs associated with the ~~net decrease in cash~~abandonment of its oil and ~~cash equivalents~~gas properties including the costs of ~~$120.2 million as previously disclosed in the consolidated statement~~reclamation 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.drilling sites. The Company ~~now applies an initial screen for determining whether a transaction involves an asset or a business. When substantially all of~~records the fair value of a liability for a legal obligation to retire an asset in the ~~gross assets acquired~~period in which the liability 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 includesincurred with an ~~input and a substantive process that together significantly contribute~~offsetting increase to the ~~ability to create an output. The Company’s acquisition of the Santana and Nancy Burdine-Maxine~~related 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 impliedproperties. The fair value of ~~goodwill~~an asset retirement obligation is measured by ~~assigning~~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 for furniture and fixtures, computer equipment and automobiles is provided using the straight-line method over the useful life of the asset. 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

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 ~~all of its~~perform the goodwill impairment test. The impairment test requires allocating goodwill and certain other assets and liabilities ~~as if that~~to assigned reporting units. The fair value of each reporting unit ~~had been acquired in a business combination. Goodwill~~is estimated and compared with its net book value. An impairment ~~will now be~~loss is recognized if the ~~amount by which a reporting unit’s carrying value exceeds its~~estimated fair value of the reporting unit is less than its carrying amount, not ~~to exceed~~exceeding the carrying amount of ~~goodwill. ASU 2017-04~~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 ~~effective for annual~~estimated based upon estimated future cash flows of the reporting ~~periods and interim reporting periods within those annual reporting periods, beginning after December 15, 2019. Early adoption is permitted. At~~unit. The goodwill relates entirely to Colombia. The Company performed step 1 test of goodwill impairment at December 31, ~~2017, the Company performed a qualitative assessment of goodwill~~2019, and ~~based on this assessment, no~~0 impairment of goodwill was identified.

~~Recently Issued Accounting Pronouncements~~Convertible Notes

The Company accounted 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 the 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 we've presented as a direct deduction against the carrying amount of the Convertible Notes and were amortized to interest expense using the effective interest method.

As at December 31, 2019, there were 0 Convertible Notes outstanding and all debt issuance costs relating to the Convertible Notes were expensed in the period.

Revenue from Contracts with Customers

The Company's revenue relates to oil and natural gas sales in Colombia. The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.

The Company evaluates its arrangement with third parties and partners to determine if the Company acts as a principal or an agent. In ~~May 2014,~~making this evaluation, management considers if the ~~FASB issued guidance regarding~~Company obtains control of the ~~accounting~~product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by the Company from the transaction.

Tariffs, tolls and fees charged to other entities for use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with ~~customers. In August 2015,~~customers or from incidental arrangements. When determining if the ~~FASB issued ASU 2015-14, “Revenue from Contracts with Customers - Deferral~~Company acted as a principal or as an agent in transactions, management determines if the Company obtains control of the ~~Effective Date”.~~ product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.

In 2017, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.

Stock-based compensation

The ~~ASU deferred~~Company records stock-based compensation expense in its consolidated financial statements measured at the ~~effective~~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.

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

Earnings (loss) per share

Basic earnings (loss) per share is calculated by dividing net income or 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

Leases

The Company adopted Accounting Standard Codification ("ASC") 842 Leases with a 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 guidanceinitial application on ~~principal versus agent considerations. In April, May and December 2016,~~January 1, 2019 in accordance with 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 transition approach using the practical expedients available for land easements and short-term leases. The Company did not elect the "suite" of practical expedients or use the hindsight expedient in its adoption.

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to ~~adjust retained earnings.~~control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, the Company allocates the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.

The Company has ~~completed its evaluation~~applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether the Company is reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.

All leases identified as part of the ~~impact~~transition relate to office leases.

The transition resulted in the recognition of ~~the ASU and has reviewed its various revenue streams and underlying contracts. The Company adopted the new standard using the modified retrospective method~~a right-of-use asset presented in other capital assets of $3.8 million at ~~the date of adoption,~~ January 1, ~~2018. Adoption~~2019, the recognition of ~~the ASU did not have~~lease liabilities of $4.2 million and a ~~material~~$0.4 million impact on retained earnings. When measuring the ~~Company’s consolidated financial statements, other than enhanced disclosure related to revenues from contracts with customers as prescribed by ASU.~~lease

~~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 onliabilities, the Company's ~~consolidated financial position, results of operations or cash flows or disclosure.~~incremental borrowing rate was used. At January 1, 2019 the rates applied ranged between 5.6% and 9.1%.

Recently Issued Accounting Pronouncements

~~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. In December 2019, the FASB issued ASU 2019-10, "Financial Instruments - Credit Losses, Derivatives and Hedging and Leases", which is codification improvement of ASU 2016-13. 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~~has adopted this ASU on January 1, 2020 and applied a current expected credit loss model that has resulted in no impact ~~this update will~~

~~have~~ on ~~its~~Company's consolidated ~~financial~~ position, results of ~~operations,~~operation or cash ~~flows, and disclosure.~~flows.

3. Segment and Geographic Reporting

The Company is primarily engaged in the exploration and production of oil ~~and natural gas.~~in Colombia. The Company has ~~one~~1 reportable segment based on geographic organization, Colombia. For the year ended December 31, 2019, the Ecuador business unit was not significant and was therefore included in the Colombia reportable segment. 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 separate reportable segments. The "All Other" category represents the Company’s corporate activities, and the 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 comparative information on the Company’s reportable segment and other ~~activities:~~

activities for the year ended December 31, 2017:



	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, 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)	2019		2018
Trade	$	24,890	$	16,332
Other	11,401		9,845
	$	36,291	$	26,177

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,						As at December 31,
(Thousands of U.S. Dollars)	2017			2016			2019			2018
Oil and natural gas properties
Proved	$	2,810,796		$	2,652,171		$	3,850,565		$	3,226,811
Unproved	464,948			647,774			310,809			456,598
	3,275,744			3,299,945			4,161,374			3,683,409
Other(1)	26,401			29,445			26,287			19,549
	3,302,145			3,329,390			4,187,661			3,702,958
Accumulated depletion, depreciation and impairment	(2,202,921		)	(2,262,781		)
Accumulated depletion and depreciation							(2,610,268		)	(2,390,181		)
	$	1,099,224		$	1,066,609		$	1,577,393		$	1,312,777

⁽¹⁾ Included in other is right-of-use assets for operating and finance leases which totaled $5.7 million as at December 31, 2019 (December 31, 2018 - nil).

Depletion and depreciation expense on property, plant and equipment for the year ended December 31, ~~2017,~~2019, was ~~$126.8~~$220.8 million (year ended December 31, ~~2016~~2018 - ~~$130.2~~$197.0 million; year ended December 31, ~~2015~~2017 - ~~$177.9~~$126.8 million). A portion of depletion and depreciation expense was recorded as oil inventory in each ~~year and adjusted for inventory changes.~~year.

Asset impairment for the three years ended December 31, ~~2017,~~2019, was as follows:



(Thousands of U.S. Dollars)	Year Ended December 31,
	2019		2018		2017
Impairment of oil and gas properties	$	—	$	—	$	1,514

(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~~$64.20 per bbl for the purposes of the December 31, ~~2017~~2019 ceiling test calculations ~~(September 30, 2017~~(December 31, 2018 - ~~52.70, June 30, 2017 - $51.35, March~~$72.08; December 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)~~$54.19).

2019 Acquisitions

On February 20, 2019, the Company acquired 36.2% working interest ("WI") in the Suroriente Block and a 100% WI of the Llanos-5 Block for cash consideration of $79.1 million and a promissory note of $1.5 million included in current accounts payable on the Company's consolidated balance sheet. The cost of the assets was allocated to proved properties using relative fair values. The entire consideration of $0.3 million for Llanos-5 was allocated to unproved properties.

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.



(Thousands of U.S. Dollars)
Cost of asset acquisition:
Cash	$	79,100
Promissory note	1,500
	$	80,600

Allocation of Consideration Paid:
Oil and gas properties
Proved	$	52,530
Unproved	44,768
	97,298
Net working capital (including cash acquired of $5.3 million)	(16,698		)
	$	80,600

~~Acquisition of Santana and Nancy Burdine-Maxine Blocks~~

2018 Acquisitions

On ~~April 27, 2017,~~October 1, 2018, the Company acquired the ~~Santana~~remaining 45% WI in the PUT-1 Block in the Putumayo Basin for cash consideration of $28.1 million, of which $15.2 million was allocated to proved properties.

On August 6, 2018, the Company acquired a WI in the VMM-2 Block in the Middle Magdalena Valley Basin for cash consideration of $17.0 million, of which $6.2 million was allocated to proved properties. On December 1, 2018, the Company acquired a further WI in the VMM-2 Block for cash consideration of $5.0 million, of which $1.6 million was allocated to proved properties. In total, the Company has acquired an 80% WI in the VMM-2 Block. The Company acquired the remaining 20% WI in the Block in 2019.

On June 20, 2018, the Company acquired the remaining WI in the Alea 1848-A and ~~Nancy-Burdine-Maxine~~1947-C 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$3.1 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.~~entirely recorded to unproved properties.

~~Disposition of Peru Business Unit~~2017 Dispositions

~~On December 18,~~In 2017 Gran Tierra completed the sale of its Peru and Brazil 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~~units. The net book value of the Peru business unit was greater than proceeds received ~~resulting~~and resulted 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,~~sale while the net book value of the Brazil business unit was greater than proceeds received ~~resulting~~and resulted in a $10.2 million loss on sale. Both losses were included in Other Loss.

Unproved Oil and Natural Gas Properties

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,~~2019, unproved oil and natural gas properties consist of exploration lands held in ~~Colombia.~~Colombia and Ecuador. 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%~~100% of costs not subject to depletion at December 31, ~~2017,~~2019, 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:~~2019:



	Costs Incurred in
(Thousands of U.S. Dollars)	2019		2018		2017		Prior to 2017		Total
Acquisition costs - Colombia	$	21,773	$	14,115	$	10,700	$	135,202	$	181,790
Exploration costs - Colombia	56,454		34,349		12,209		22,799		125,811
Exploration costs - Ecuador	3,208		—		—		—		3,208
	$	81,435	$	48,464	$	22,909	$	158,001	$	310,809

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~~2019 and ~~2016,~~2018, was as follows:



	As at December 31,
(Thousands of U.S. Dollars)	2019			2018
6.25% Senior Notes	$	300,000		$	300,000
7.75% Senior Notes	300,000			—
Convertible Notes (b)	—			115,000
Revolving credit facility (c)	118,000			—
Unamortized debt issuance costs	(21,081		)	(15,585		)
Long-term lease obligation⁽¹⁾	3,540			—
Long-term debt	$	700,459		$	399,415

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.~~ ⁽¹⁾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 anycurrent portion of the ~~Convertible~~lease obligation has been included in accounts payable and accrued liabilities on the Company's balance sheet and totaled $3.3 million as at December 31, 2019 (December 31, 2018 - nil).

Senior Notes ~~at its option, on or after April 5,~~

On May 20, 2019, ~~if (terms below~~the Company, issued $300.0 million of 7.75% Senior Notes due 2027 (the “7.75% Senior Notes”). The 7.75% Senior Notes are ~~as defined in the indenture governing the Convertible Notes):~~

~~(i) the last reported sale price~~fully and unconditionally guaranteed by certain subsidiaries 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.

guarantee its revolving credit facility. Net proceeds from the ~~sale~~issue of the ~~Convertible~~7.75% Senior Notes were ~~$109.1~~$289.3 million, after deducting the initial purchasers' ~~discount~~discounts and commission and the offering expenses payable by the Company.

~~b) Credit Facility~~The 7.75% Senior Notes bear interest at a rate of 7.75% per year, payable semi-annually in arrears on May 23 and November 23 of each year, beginning on November 23, 2019. The 7.75% Senior Notes will mature on May 23, 2027, unless earlier redeemed or repurchased.

Before May 23, 2023, the Company may, at its option, redeem all or a portion of the 7.75% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a “make-whole” premium. Thereafter, the Company may redeem all or a portion of the 7.75% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2023 - 103.875%; 2024 - 101.938%; 2025 and thereafter - 100%.

On February 15, 2018, Gran Tierra Energy International Holdings Ltd. ("GTEIH"), an indirect, wholly-owned subsidiary of the Company, issued $300.0 million of 6.25% Senior Notes due 2025 (the “6.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Senior Notes”). The 6.25% Senior Notes are fully and unconditionally guaranteed by the Company and certain subsidiaries of the Company that guarantee its revolving credit facility. Net proceeds from the sale of the 6.25% Senior Notes were $288.1 million, after deducting the initial purchasers' discounts and commission and the offering expenses payable by the Company.

The 6.25% Senior 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 6.25% Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

Before February 15, 2022, GTEIH may, at its option, redeem all or a portion of the 6.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 6.25% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2022 - 103.125%; 2023 - 101.563%; 2024 and thereafter - 100%.

Convertible Notes

During the year, the Company purchased and canceled $114,999,000 aggregate principal amount of Convertible Notes, including $114,997,000 aggregate principal amount purchased and canceled pursuant to an offer to purchase for cash all outstanding Convertible Notes, at a purchase price of $1,075 in cash per $1,000 principal amount of Convertible Notes plus $1.6 million of accrued and unpaid interest outstanding on such Convertible Notes up to, but not excluding the date of purchase. The Company

recorded $11.5 million loss on redemption including the premium paid, transaction costs and the expensing of unamortized deferred financing fees of $2.3 million. At December 31, ~~2017,~~2019, the Company had 0 Convertible Notes outstanding.

Credit Facility

At December 31, 2019, the Company had a revolving credit facility with a syndicate of lenders with a borrowing base of ~~$300~~$300.0 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,~~2019, the borrowing base of ~~$300~~$300.0 million was reaffirmed and, among other things, the maturity date of the borrowing under the revolving credit facility was extended from ~~October 1, 2018~~November 10, 2021 to November 10, ~~2020.~~ 2022. The next re-determination of the borrowing base is due to occur no later than May ~~2018.~~2020.

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%~~1.65% to 3.65% (December 31, ~~2016~~2018 - ~~2.00%~~1.65% to ~~3.00%~~3.65%), or an alternate base rate plus a margin ranging from ~~1.15%~~0.65% to 2.65% (December 31, 2018 - 0.65% 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%~~0.41% to 0.91% (December 31, ~~2016~~2018 - ~~0.75%~~0.41% to 0.91%) 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)d) 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)	2019		2018		2017
Contractual interest and other financing expenses	$	39,892	$	24,181	$	11,467
Amortization of debt issuance costs	3,376		3,183		2,415
	$	43,268	$	27,364	$	13,882

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 Senior Notes, Convertible Notes and its revolving credit facility. As at December 31, ~~2017,~~2019, 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



	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
Shares repurchased and canceled	(7,704,381	)	—		—
Exchange of exchangeable shares	2,088,229		(389,816	)	(1,698,413	)
Balance, December 31, 2017	385,191,042		4,422,776		1,688,889
Options exercised	549,189		—		—
Shares repurchased and canceled	(4,772,869	)	—
Exchange of exchangeable shares	6,111,665		(4,422,776	)	(1,688,889	)
Balance, December 31, 2018	387,079,027		—		—
Shares repurchased and canceled	(20,097,471	)	—		—
Balance, December 31, 2019	366,981,556		—		—

The Company’s authorized share capital consists of ~~595,000,002~~595,000,000 shares of capital stock, of which ~~570 million~~ ~~are~~570,000,000 was designated as Common Stock, par value ~~$0.001~~$0.001 per share ~~25 million~~ ~~are designated~~and 25,000,000 as Preferred Stock, par value ~~$0.001~~$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~~On July 5, 2018, Gran Tierra Exchangeco Inc., ~~(the "Exchangeco~~a wholly-owned subsidiary of the Company, redeemed all of its outstanding exchangeable ~~shares") and~~ ~~1,688,889~~ ~~exchangeable~~ shares which were acquired for purchase consideration of 1 share of Gran Tierra ~~Goldstrike Inc. (the "Goldstrike~~common stock for each exchangeable ~~shares"). The Exchangeco~~share. On July 9, 2018, the Company retired and canceled 1 share of Special A Voting Stock and 1 share of Special B Voting Stock, which held voting rights in connection with those exchangeable shares. As a result, no 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,~~Special A Voting Stock 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.Special B Voting Stock remain outstanding.

The holders of shares of Common Stock are entitled to ~~one~~1 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,~~In 2019, the Company ~~announced that it had~~ implemented a share repurchase program (the ~~“2017 Program”~~“2019 program”) through the facilities of the Toronto Stock Exchange ~~(“TSX”~~("TSX")~~, the NYSE American~~ and eligible alternative trading platforms in ~~Canada and the United States.~~Canada. Under the ~~2017 Program,~~2019 program, the Company is able to purchase at prevailing market prices up to ~~19,540,359~~19,353,951 shares of Common Stock, representing ~~5.0%~~approximately 5% of the issued and outstanding shares of Common Stock as of ~~January 27, 2017. Shares~~March 1, 2019. The 2019 program was scheduled to expire on March 12, 2020, or earlier if the 5% share maximum is reached. The 2019 program expired when the 5% share maximum was reached in September 2019.The weighted average price per share under the 2019 program was $1.85 per share. All shares purchased ~~pursuant~~were canceled subsequent to the ~~2017 Program will be canceled. The 2017 Program expired on February 7, 2018.~~repurchase.

During the year ended December 31, 2019, the Company repurchased 20,097,471 shares of Common Stock at a weighted average price of $1.87 per share. Of the shares repurchased, 743,520 shares at a weighted average price of $2.34 per share were repurchased under 2018 share purchase program implemented in 2018 with similar terms to that of the 2019 program.

Equity Compensation Awards

The Company has an equity compensation program in place for its executives, employees and ~~employees. Equity~~directors. Executives and employees are given equity compensation grants that vest ~~either~~ based ~~solely~~ on a recipient's continued employment orand in the case of Performance Share Units (“PSUs”), the number of units that vest is dependent upon the achievement of certain key ~~measures of performance.~~performance measures. Equity settled awards consist 80% of ~~Performance Stock Units (“PSUs”)~~PSUs and 20% of stock options. The Company’s ~~equity~~stocked based compensation awards outstanding as at December 31, ~~2017,~~2019, include PSUs, deferred share units (“DSUs”), ~~restricted stock units (“RSUs”)~~ and stock options.

In accordance with the 2007 Equity Incentive Plan, as amended, 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:~~2019:


	PSUs		DSUs	RSUs		Stock Options					PSUs		DSUs	Stock Options
	Number of Outstanding Share Units					Number of Outstanding Stock Options		Weighted Average Exercise Price /Stock Option ($)			Number of Outstanding Share Units			Number of Outstanding Stock Options		Weighted Average Exercise Price /Stock Option ($)
Balance, December 31, 2016	3,362,717		208,698	359,145		9,239,478		$	4.16
Balance, December 31, 2018											9,004,661		684,893	9,034,412		$	3.18
Granted	3,422,170		247,070	—		2,029,035		2.54			6,355,214		567,101	2,943,990		2.04
Exercised	—		—	(224,548	)	—		—			(2,725,877	)	—	—		—
Forfeited	(652,936	)	—	(12,507	)	(911,154	)	(4.79		)	(1,262,631	)	—	(1,213,170	)	3.61
Expired	—		—	—		(1,396,667	)	(4.65		)	—		—	(152,360	)	5.27
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
Balance, December 31, 2019											11,371,367		1,251,994	10,612,872		$	2.78
Vested and exercisable, at December 31, 2019											��			6,469,699		$	3.14
Vested, or expected to vest, at December 31, 2019 through the life of the options														10,445,530		$	2.79

Stock-based compensation expense for the year ended December 31, ~~2017,~~2019, was ~~$9.8~~$1.4 million (December 31, ~~2016~~2018 - ~~$6.3~~$8.3 million; December 31, ~~2015~~2017 - ~~$2.7~~$9.8 million) and was primarily recorded in G&A expenses.

At December 31, ~~2017,~~2019, there was ~~$13.7~~$6.7 million (December 31, ~~2016~~2018 - ~~$10.0~~$9.2 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~~

1.7 years. The weighted-average remaining contractual term of options vested, or expected to vest, at December 31, ~~2017~~2019 was ~~2.9~~2.3 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~~Upon vesting, the underlying number of ~~PSUs that vest~~Common Shares or the cash payment equivalent to their value may range from ~~zero~~0 to 200% of the ~~target~~ number ~~granted~~of PSU's vested, based on the Company’s performance with respect to the applicable performance targets. As at December 31, 2019, 2.4 million (December 31, 2018 - 2.7 million) of PSU's had vested and will be settled in cash. The performance targets for the PSUs outstanding as at December 31, ~~2017,~~2019, 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~~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,~~2019, 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 Company currently intends to settle 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).~~DSUs in cash.

Stock Options

Each stock option permits the holder to purchase ~~one~~1 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~~2019, 0 stock options were exercised and no0 cash proceeds were received (~~2016~~(2018 – ~~2,165,370~~549,189 options exercised and shares issued; ~~2015~~2017 – ~~390,000~~0 options exercised and 0 shares issued).

At December 31, ~~2017~~2019, the weighted average remaining contractual term of outstanding stock options was ~~2.9~~2.3 years, ~~and of~~ (exercisable stock options ~~was~~ ~~2.5~~ ~~years.~~- 1.3 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,
	2019		2018		2017
Dividend yield (per share)	NaN		NaN		NaN
Volatility	48% to 54%		51% to 55%		51% to 53%
Weighted average volatility	51	%	54	%	52	%
Risk-free interest rate	1.49% to 2.54%		2.18% to 3.00%		1.75% to 2.10%
Expected term	4-5 years		4-5 years		4-5 years

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 endedDecember 31, ~~2017~~,2019, was ~~$1.11~~ (~~2016~~$0.89 (2018 - ~~$1.14~~; ~~2015~~$1.15; 2017 - ~~$1.24~~)$1.11). The weighted average grant date fair value for options vested in the year endedDecember 31, ~~2017~~,2019, was ~~$1.31~~ (~~2016~~$1.10 (2018 - ~~$1.52~~; ~~2015~~$1.23; 2017 - ~~$2.38~~)$1.31). The total fair value of stock options vested during year endedDecember 31, ~~2017~~,2019, was ~~$2.5~~$1.9 million (~~2016~~ (2018 - ~~$2.8 million~~; ~~2015~~$2.8 million; 2017 - ~~$6.8 million~~)$2.5 million).

Weighted Average Shares Outstanding



	Year Ended December 31,
	2019		2018		2017
Weighted Average number of common and exchangeable shares outstanding	376,495,306		390,930,453		396,683,593
Shares issuable pursuant to stock options	87,204		4,207,542		—
Shares assumed to be purchased from proceeds of stock options	(74,698	)	(3,832,516	)	—
Shares issuable on conversion of Convertible Notes	—		35,814,393		—
Weighted average number of diluted common and exchange shares outstanding	376,507,812		427,119,872		396,683,593

For the year endedDecember 31, ~~2017~~, ~~9,681,304~~2019, 9,465,737 options, on a weighted average basis, (~~2016~~(2018 - ~~10,662,034~~5,354,545 options; ~~2015~~2017 - ~~13,432,287~~9,681,304 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)	2019			2018
Balance, beginning of year	$	43,799		$	31,564
Liability incurred	7,034			6,985
Settlements	(846		)	(600		)
Accretion	3,436			2,772
Revisions in estimated liability	(10,004		)	2,351
Liabilities assumed in acquisitions	—			727
Balance, end of year	$	43,419		$	43,799

Asset retirement obligation - current	$	—		$	123
Asset retirement obligation - long-term	43,419			43,676
Balance, end of year	$	43,419		$	43,799

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,~~2019, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was ~~$12.7~~$2.8 million (December 31, ~~2016~~2018 - ~~$12.0~~$2.7 million). These assets were accounted for as restricted cash and cash equivalents on the Company's balance sheet.

9. Revenue

Most of the Company's revenue is generated 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 ICE Brent and adjusted for Vasconia or Castilla crude differentials, and quality and transportation discounts each month. For the year ended December 31, 2019, 100% (year ended December 31, 2018 - 100%, year-end December 31, 2017 - 99%) of the Company's revenue resulted from oil sales and quality and transportation discounts were 16% (year ended December 31, 2018 - 18%, year ended December 31, 2017 - 21%) of the ICE Brent price. During the year ended December 31, 2019, the Company's production was sold primarily to three major customers in Colombia (year ended December 31, 2018 - two, year-end December 31, 2017 - three).

As at December 31, 2019, accounts receivable included $0.1 million of accrued sales revenue related to December 2019 production (As at December 31, 2018, $4.2 million related to December 2018 production).

10. 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)	2019			2018			2017
Income (loss) before income taxes
United States	$	(27,984	)	$	(14,610	)	$	(51,215	)
Foreign	123,959			166,097			88,545
	95,975			151,487			37,330
Statutory rate ⁽¹⁾	33		%	37		%	35		%
Income tax expense expected	31,672			56,050			13,066
Impact of foreign taxes	9,387			7,011			12,310
Foreign currency translation	11,527			10,336			(118		)
Other local taxes	504			524			1,056
Stock-based compensation	430			324			2,001
Change in valuation allowance	3,429			(21,954		)	52,269
Non-deductible third party royalty in Colombia	2,240			3,194			3,194
Other permanent differences	(1,904		)	(6,614		)	(14,740		)
Total income tax expense	$	57,285		$	48,871		$	69,038

Effective tax rate	60		%	32		%	185		%

Current income tax expense
United States	$	—		$	—		$	3,457
Foreign	17,058			43,903			20,865
	17,058			43,903			24,322
Deferred income tax expense
Foreign	40,227			4,968			44,716
Total income tax expense	$	57,285		$	48,871		$	69,038

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~~ The tax rate in 2019 and 2018 is the statutory rate in Colombia. The tax rate in 2017 is the statutory rate in the ~~rate reconciliation are tax effected at~~U.S.

In general, it is the ~~35% statutory rate~~Company's practice and ~~were primarily due~~intention to ~~higher income tax rates in Colombia. Impact of foreign taxes for~~reinvest 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~~our non-U.S. subsidiaries asin such subsidiaries' operations. As of December 31, ~~2017, were considered~~2019, the Company has not made a provision for U.S. or additional foreign withholding taxes on the investments in foreign subsidiaries that are indefinitely reinvested. Generally, such amounts become subject to ~~be permanently reinvested. A determination~~taxation upon the remittance of ~~the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.~~dividends and under certain other circumstances.

In the fourth quarter of ~~2016,~~2019, the Colombia government enacted a new tax reform to replace the 2018 tax reform, which was overturned by the Colombian ~~government~~Constitutional Court. This new tax reform maintains the same corporate tax rates that were approved

by Congress in 2018. The enacted corporate tax ~~legislation consolidating the corporate Income~~rates are 32% for 2020, 31% for 2021 and ~~CREE taxes into a single income tax at 40%~~30% for ~~2017 (including a surtax of 6%), 37% for 2018 (including a surtax of 4%) and 33% for 2019~~2022 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.



	As at December 31,
(Thousands of U.S. Dollars)	2019			2018
Deferred tax assets
Tax benefit of operating loss carryforwards	$	73,096		$	51,042
Tax basis in excess of book basis	544			8,854
Foreign tax credits and other accruals	76,720			79,820
Tax benefit of capital loss carryforwards	22,710			32,737
Deferred tax assets before valuation allowance	173,070			172,453
Valuation allowance	(129,067		)	(127,016		)
	44,003			45,437
Deferred tax liabilities	59,762			23,419
Net deferred tax (liabilities) assets	$	(15,759	)	$	22,018

~~The US government enacted the Tax Cuts and Jobs Act of 2017 (“TCJA”) on December 22, 2017. As of~~

At December 31, ~~2017, the Company is still evaluating the complete tax effects of the enactment of the TCJA. However,~~2019, the Company has ~~determined a reasonable estimate~~not recognized the benefit of unused non-capital loss carryforwards of $50.5 million (2018 - $22.7 million) for federal purposes in the ~~impact of the TCJA on its existing deferred tax balances and the one-time transition tax. Based on this estimate,~~United States, which expire from 2029 to 2039.

At December 31, 2019, the Company has ~~determined that~~not recognized the ~~there is no current~~benefit of unused non-capital loss carryforwards of $31.5 million

(2018 - $27.1 million) for federal and provincial purposes in Canada, which expire from 2025 to 2039. The Company has not recognized the benefit of capital loss carry forwards of $197.5 million (2018 - $242.4 million) for federal and provincial purposes in Canada which can be carried forward indefinitely.

At December 31, 2019, the Company has recognized the benefit of unused non-capital loss carryforwards of $140.5 million (2018 - $99.0 million), out of a total of $159.2 million and tax ~~expense impact to its financial statements as~~credits of $1.5 million (2018 - $2.2 million), out of a total of $3.3 million, for federal purposes in Colombia. As a result of the ~~TCJA. The Company has also calculated an estimated deferred~~2016 Colombian Tax Reform, Colombian losses can be carryforward for a period of 12 years, and not indefinitely as under the previous tax ~~asset impact of $59 million, which~~regime. There is ~~subject~~a grandfathering rule for losses incurred prior 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~~continue to be carried forward indefinitely. ~~Capital~~$75.4 million of the Colombian losses can be carried forward ~~indefinitely.~~indefinitely and $83.8 million are entitled to a carryforward period of 12 years.

As at December 31, 2019 and 2018, Gran Tierra had 0 unrecognized tax benefits and related interest and penalties included in its deferred and current tax liabilities in the consolidated balance sheet. The ~~valuation allowance decreased by $152.6 million during~~Company does not anticipate any material changes with respect to unrecognized tax benefit within the ~~year~~next twelve months. The Company had no other significant interest or penalties related to taxes included in the consolidated statement of operations for the quarter 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.

2019. The Company and its subsidiaries file income tax returns in the U.S. ~~federal and state jurisdictions~~ and certain other foreign jurisdictions. The Company is ~~potentially~~ subject to income tax examinations for ~~open~~the tax years ~~2009~~ended 2011 through ~~2016~~2019 in certain jurisdictions.

~~jurisdictions. To~~In the ~~extent interest and penalties may be assessed by taxing authorities on any underpayment~~fourth quarter of ~~income~~2019, $1.4 million of value added tax ~~such amounts have been accrued and are classified~~receivable was written-off mainly as a ~~component~~result of ~~income taxes~~internal restructuring of our Colombian entities in ~~the consolidated statement of operations.~~order to drive efficiency and reduce costs.

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.~~11. Accounts Payable and Accrued Liabilities



	Year Ended December 31,
(Thousands of U.S. Dollars)	2019		2018
Trade	$	151,747	$	123,905
Royalties	5,758		3,550
Employee compensation	6,861		8,195
Other	31,147		19,020
	$	195,513	$	154,670

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.~~

12. Commitments and Contingencies

Purchase Obligations, Firm Agreements and Leases

As at December 31, ~~2017~~,2019, future minimum payments under non-cancelable agreements with remaining terms in excess of one year were as follows:



	Year ending December 31
	Total		2020		2021		2022		2023		2024		Thereafter
(Thousands of U.S. Dollars)
Oil transportation services	$	3,211	$	3,211	$	—	$	—	$	—	$	—	$	—
Drilling, completions and seismic	21,409		7,602		7,580		6,089		19		20		99
Operating leases ⁽¹⁾	5,679		2,708		1,694		1,277		—		—		—
Finance leases ⁽¹⁾	6,232		2,760		3,192		84		84		84		28
	$	36,531	$	16,281	$	12,466	$	7,450	$	103	$	104	$	127

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

$ —
⁽¹⁾ including maintenance and operating costs

Gran Tierra has operating leases ~~certain~~for office ~~space,~~spaces and finance leases for water flood facilities and storage tanks and commitments relating to 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~~Credit

At December 31, ~~2017~~,2019, the Company had provided ~~promissory notes~~letters of credit and other credit support totaling ~~$76.0~~$120.6 million (~~December~~(December 31, ~~2016~~2018 - ~~$96.8~~$76.7 million) as security ~~for letters of credit~~ relating to work commitment guarantees contained in exploration contracts in Colombia and Ecuador 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.~~pending including a dispute with the ANH relating to the calculation of HPR royalties. 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.~~13. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk

Financial Instruments

At December 31, ~~2017~~,2019, the Company’s financial instruments recognized in the balance sheet consist ~~of;~~of cash and cash ~~equivalents;~~equivalents, restricted cash and cash ~~equivalents;~~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~~receivable, investment, derivatives, accounts payable and accrued liabilities, long-term debt, current and long-term equity compensation reward liability 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~~Company's investment ~~which was received as consideration on the sale of the Company's Peru business unit~~in PetroTal was estimated ~~using quoted prices~~to be $94.7 million as at December 31, ~~2017 and~~2019 based on the ~~market exchange rate~~closing stock price of PetroTal of $0.38 or $0.50 CAD per share as 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.December 31, 2019 ( December 31, 2018 - $0.17 or $0.24 CAD per share).

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,~~2019, and December 31, ~~2016~~2018 were as follows:



	As at December 31,
(Thousands of U.S. Dollars)	2019		2018
Investment - current and long-term assets	$	94,741	$	41,435
	$	94,741	$	41,435

Derivative liability	$	775	$	1,017
PSU and DSU liability	7,859		17,683
	$	8,634	$	18,700

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~~gains or ~~gains~~losses on financial instruments recognized in the accompanying consolidated statements of operations:



(Thousands of U.S. Dollars)	Year Ended December 31,
	2019			2018			2017
Commodity price derivative loss	$	3,642		$	13,972		$	17,327
Foreign currency derivative loss (gain)	27			(890		)	(1,287		)
Investment gain	(49,884		)	(786		)	(111		)
	$	(46,215	)	$	12,296		$	15,929

(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~~gains or losses 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.

Financial instruments not recorded at fair value at December 31, 2019 include the Senior Notes and the Revolving Credit Facility (Note 6). At December 31, 2019, the carrying amounts of the 6.25% Senior Notes and 7.75% Senior Notes were $290.7 million and $289.9 million, respectively, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair values were $272.8 million and $279.1 million. The fair value of the Revolving Credit Facility approximates its carrying value. The fair value of the Senior Notes is determined based on quoted market prices considered Level 1 inputs. The fair value of the Revolving Credit Facility is estimated based on the amount the Company would have to pay a third party to assume the debt, including the 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 debt to new issuances (secured or unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of the Revolving Credit Facility was estimated using level 2 inputs.

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.

At December 31, ~~2017,~~2019, the fair value of current portion of the investment ~~RSU~~ and DSU liability was determined using Level 1 inputs and the fair value of derivatives and PSUs was determined using Level 2 ~~inputs and the~~inputs. The fair value of the long-term portion of the investment restricted by escrow conditions was previously 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)	2019			2018
Opening balance	$	8,711		$	19,147
Transfer from long-term (Level 3) to current (Level 1)	(11,881		)	(10,522		)
Unrealized gain on valuation	2,604			846
Unrealized gain (loss) on foreign exchange	566			(760		)
Closing balance	$	—		$	8,711

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~~Risk

The Company ~~utilizes~~may at time utilize 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 As at December 31, ~~2017,~~2019, the Company had outstanding commodity price derivative positions as follows:



Period and type of instrument	Volume, bopd	Reference	Purchased Put ($/bbl, Weighted Average)	Sold Call ($/bbl, Weighted Average)	Premium ($/bbl, Weighted Average)
Collars: January 1, to June 30, 2020	6,000	ICE Brent	55.00	69.05	n/a

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~~is exposed to foreign ~~currency derivatives~~exchange risk in relation to ~~manage the variability~~its Colombian operations predominantly 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 To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign exchange derivatives. As at December 31, ~~2017,~~2019 and subsequent to, 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)

Amount Hedged
(Millions COP)

U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)⁽¹⁾

Reference

Floor Price
(COP, Weighted Average)

Cap Price (COP, Weighted Average)

Collars: January 1, 2018 to December 31, 2018

174,000

58,311

COP

3,000

3,107

Collars: January 1, to December 31, 2020

134,500

40,994

COP

3,305

3,423

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~~,2019, 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~~2019 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~~.2019. The effectiveness of our internal control over financial reporting as of December 31, ~~2017~~2019 has been audited by ~~Deloitte~~KPMG LLP, ~~the~~an 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~~Controls over Financial Reporting

There were no changes in our internal ~~control~~controls over financial reporting during the ~~quarter~~three months ended December 31, ~~2017~~,2019, that have materially affected, or are reasonably likely to materially affect our internal ~~control~~controls 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~~Over Financial Reporting

We have audited ~~the~~Gran Tierra Energy Inc.’s (the Company) internal control over financial reporting ~~of Gran Tierra Energy Inc.and subsidiaries (the “Company”)~~ as of December 31, ~~2017,~~2019, based on criteria established inInternal ~~Control-Integrated~~Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway ~~Commission (COSO).~~Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2017,~~2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by ~~COSO.~~

the Committee of Sponsoring Organizations of the Treadway Commission.

We also have ~~also~~ audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2019 and ~~Canadian generally accepted auditing standards,~~2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial ~~statements as of and for the year ended December 31, 2017, of the Company~~statements), and our report dated February ~~27, 2018,~~26, 2020 expressed an unqualified opinion on those consolidated 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~~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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed ~~risk, and~~risk. Our audit also included 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~~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.~~accounting principles. 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,~~accounting principles, 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~~KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February ~~27, 2018~~26, 2020

Item 9B. Other Information

The Board of Directors of Gran Tierra Energy Inc. has established May ~~2, 2018~~6, 2020 as the date of the Company’s ~~2018~~2020 Annual Meeting of Stockholders (the ~~“2018~~“2020 Annual Meeting”) and March ~~12, 2018,~~10, 2020 as the record date for determining stockholders entitled to notice of, and to vote at, the ~~2018~~2020 Annual Meeting. The time and location of the ~~2018~~2020 Annual Meeting will be as set forth in the Company’s proxy materials for the ~~2018~~2020 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~~2020 Annual Meeting of Stockholders (our “Proxy Statement”), a copy of which will be filed with the SEC within 120 days after December 31, ~~2017.~~2019. For information with respect to our executive officers, see ~~“Executive Officers of the Registrant”~~“Information About Our Executive Officers” 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, if applicable, is incorporated by reference from the information contained in the section entitled ~~“Section~~“Delinquent Section 16(a) ~~Beneficial Ownership Reporting Compliance”~~Reports” 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.~~governance.html within four business days of such amendment or waiver. Information on our website is not incorporated into this Annual Report or otherwise made part of this Annual Report.

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:~~2019:

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⁾	(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	10,612,872	2.78	15,078,864
Equity compensation plans not approved by security holders	—	—	—	—	—	—
	8,960,692	3.65	17,280,233	10,612,872	2.78	15,078.864

⁽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"), and 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,~~2019, 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~~2019, 12,623,361 shares were issued and outstanding relating to PSUs and DSUs and, after application of the fungible factor of 1.55, these outstanding awards would represent a ~~10,400,204~~19,566,210 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��~~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	5651
Consolidated Statements of Operations	5755
Consolidated Balance Sheets	5856
Consolidated Statements of Cash Flow	5957
Consolidated Statements of Shareholders’ Equity	6058
Notes to the Consolidated Financial Statements	6159
Supplementary Data (Unaudited)	8578

(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~~3.3	~~Details~~Certificate of ~~the Goldstrike~~Retirement of Special A Voting ~~Share.~~Stock and Special B Voting Stock of Gran Tierra Energy Inc.	Incorporated by reference to Exhibit ~~10.14~~3.1 to the ~~Annual~~Current Report on Form ~~10-KSB/A for the period ended December 31, 2005, and~~8-K, filed with the SEC on ~~April 21, 2006~~July 9, 2018 (SEC File No. ~~333-111656)~~001-34018).

~~4.2~~4.1	~~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~~4.2	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~~4.3	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~~4.4	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~~4.5	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~~

4.6	First Supplemental Indenture related to 6.25% Senior Notes due 2025, dated as of July 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank National Association.	Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, filed with the SEC on August 8, 2019 (SEC File No. 001-34018).

4.7	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~~4.8	~~Voting Exchange and Support Agreement by and between Goldstrike, Inc., 1203647 Alberta Inc., Gran Tierra Goldstrike Inc. and Olympia Trust Company~~Indenture related to the 7.750% Senior Notes due 2027, dated as of ~~November 10, 2005.~~May 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank National Association.	Incorporated by reference to Exhibit ~~10.3~~4.1 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~~May 23, 2019 (SEC File No. 001-34018).

~~10.3~~4.9	~~Support Agreement,~~First Supplemental Indenture related to 7.750% Senior Notes due 2027, dated as of ~~November 14, 2008, between~~July 23, 2019, among Gran Tierra Energy Inc., ~~Gran Tierra Callco ULC~~the guarantors named therein, and ~~Gran Tierra Exchangeco Inc.~~U.S. Bank.	Incorporated by reference to Exhibit ~~10.2~~10.4 to the ~~Current~~Quarterly Report on Form ~~8-K,~~10-Q, filed with the SEC on ~~November 17, 2008~~August 8, 2019 (SEC File No. 001-34018).

~~10.4~~4.10	Form of 7.750% Senior Notes due 2027 (included as Exhibit A to Exhibit 4.1).	Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).

4.11	Description of securities.	Filed herewith.

10.1	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~~10.2	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~~ (SEC File No. 001-34018).

~~10.6~~10.3	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~~ (SEC File No. 001-34018).

~~10.7~~10.4	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~~ (SEC File No. 001-34018).

~~10.8~~10.5	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~~10.6	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~~10.7	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.~~ Incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K filed with the SEC on February 27, 2018 (SEC File No. 001-34018).

~~10.11~~10.8	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.~~ Incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed with the SEC on February 27, 2018 (SEC File No. 001-34018).

~~10.12~~10.9	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.~~ Incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K filed with the SEC on February 27, 2018 (SEC File No. 001-34018).

~~10.13~~10.10	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~~10.11	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~~10.12	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~~10.13	Form of Indemnity Agreement.*	Incorporated by reference to Exhibit ~~99.1~~3.5 to the Current Report on Form 8-K filed with the SEC on ~~April 2, 2008~~November 4, 2016 (SEC File No. ~~000-52594)~~001-34018).

~~10.17~~10.14	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~~10.15	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~~10.16	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~~10.17	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~~10.18	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~~10.19	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~~10.20	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~~10.21	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~~

10.22	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~~10.23	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~~10.24	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)~~001-34018).

~~10.33~~10.25	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~~10.26	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~~10.27	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~~10.28	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~~10.29	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~~10.30	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~~10.31	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~~10.32	Tenth Amendment to Credit Agreement, dated as of May 25, 2018, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.	Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q, filed with the SEC on August 2, 2018 (SEC File No. 001-34018)



10.33	Eleventh Amendment to Credit Agreement, dated as of December 20, 2018, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., 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 December 21, 2018 (SEC File No. 001-34018)

10.34	Twelfth Amendment to Credit Agreement, dated as of May 14, 2019, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., 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 May 15, 2019 (SEC File No. 001-34018)

10.35	Thirteenth Amendment to Credit Agreement, dated as of December 10, 2019, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., 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 December 11, 2019 (SEC File No. 001-34018)

10.36	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~~10.37	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~~10.38	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~~10.39	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~~10.40	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~~10.41	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~~10.42	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~~10.43	~~Statement re: Computation~~Sale and Purchase Agreement for all of ~~Ratio~~the issued share capital of ~~Earnings to Fixed Charges.~~Vetra Southeast S.L.U., dated February 20, 2019.	~~Filed herewith.~~ Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).

10.44	Sale and Purchase Agreement for PUT-8, dated February 20, 2019.	Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).

10.45	Sale and Purchase Agreement for LLA-5, dated February 20, 2019.	Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).

10.46	Sale and Purchase Agreement for Suroriente, dated February 20, 2019.	Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).



10.47	Executive Employment Agreement, dated October 18, 2019, between Gran Tierra Energy Canada ULC and Gran Tierra Energy Inc. and Remi Anthony Berthelet.	Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on November 6, 2019 (SEC File No. 001-34018).

21.1	List of subsidiaries.	Filed herewith.

23.1	Consent of ~~Deloitte~~KPMG LLP.	Filed herewith.

23.2	Consent of McDaniel & Associates Consultants Ltd.	Filed herewith.

23.3	Consent of Deloitte LLP.	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.



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~~2019..	~~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).~~Filed herewith.

101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH Inline XBRL Taxonomy Extension Schema Document

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document

104. Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document

* Management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

None.

~~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~~26, 2020		/s/ Gary S. Guidry
		By: Gary S. Guidry
		President and Chief Executive Officer, Director
		(Principal Executive Officer)



Date: February ~~27, 2018~~26, 2020		/s/ Ryan Ellson
		By: Ryan Ellson
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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~~26, 2020
Gary S. Guidry	(Principal Executive Officer)

/s/ Ryan Ellson	Chief Financial Officer	February ~~27, 2018~~26, 2020
Ryan Ellson	(Principal Financial and Accounting Officer)

/s/ Peter Dey	Director	February ~~27, 2018~~26, 2020
Peter Dey

/s/ Evan Hazell	Director	February ~~27, 2018~~26, 2020
Evan Hazell

/s/ Robert B. Hodgins	Director	February ~~27, 2018~~26, 2020
Robert B. Hodgins

/s/ Ronald Royal	Director	February ~~27, 2018~~26, 2020
Ronald Royal

/s/ Sondra Scott	Director	February ~~27, 2018~~26, 2020
Sondra Scott

/s/ David P. Smith	Director	February ~~27, 2018~~26, 2020
David P. Smith

/s/ Brooke Wade	Director	February ~~27, 2018~~26, 2020
Brooke Wade

~~102~~95



	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



	Oil Wells
	Gross	Net
Colombia⁽¹⁾	216.0	180.2
	216.0	180.2



Name	Age	Position
Gary S. Guidry	6264	President and Chief Executive Officer, Director
Ryan Ellson	4244	Chief Financial Officer and Executive Vice President, Finance
~~Ed Caldwell~~Tony Berthelet	6849	~~Vice President, Health, Safety and Environment & Corporate Social Responsibility~~
~~Adrian Coral~~	44	~~President, Gran Tierra Energy Colombia~~Chief Operating Officer
James Evans	5253	Vice President, Corporate Services
~~Alan Johnson~~Glen Mah	4662	Vice President, ~~Asset Management~~
~~Glen Mah~~	61	~~Vice President, Business Development~~
~~Susan Mawdsley~~	51	~~Vice President, Finance and Corporate Controller~~Exploration Ecuador
Rodger Trimble	5657	Vice President, Investor Relations
Lawrence West	6162	Vice President, Exploration



	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



	(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



	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



	Developed		Undeveloped ⁽²⁾		Total
	Gross	Net	Gross	Net	Gross	Net
Colombia⁽¹⁾	340,310	247,921	1,620,955	1,548,130	1,961,265	1,796,051
Ecuador	—	—	138,239	138,239	138,239	138,239
Total	340,310	247,921	1,759,194	1,686,369	2,099,504	1,934,290


Statement of Operations Data
	Year Ended December 31,															Year Ended December 31,
	2017			2016			2015			2014			2013			2019			2018		2017			2016			2015
Oil and natural gas sales	$	421,734		$	289,269		276,011			$	559,398		$	646,955		$	570,983		$	613,431	$	421,734		$	289,269		$	276,011

Expenses
Operating	109,869			86,925			75,565			89,753			91,223			142,086			111,272		87,855			64,173			60,756
Workover																41,118			34,437		22,014			22,752			14,809
Transportation	25,107			31,776			40,204			24,196			18,949			20,400			28,993		25,107			31,776			40,204
Depletion, depreciation and accretion	131,335			139,535			176,386			185,877			200,851			225,033			197,867		131,335			139,535			176,386
Asset impairment	1,514			616,649			323,918			265,126			2,000			—			—		1,514			616,649			323,918
G&A	39,014			33,218			32,353			51,249			41,115
General and administrative																34,730			39,483		39,014			33,218			32,353
Severance	1,287			1,319			8,990			—			—			1,771			2,361		1,287			1,319			8,990
Transaction	—			7,325			—			—			—			—			—		—			7,325			—
Equity tax	1,224			3,098			3,769			—			—			—			—		1,224			3,098			3,769
Foreign exchange loss (gain)	2,067			(1,469		)	(17,242		)	(39,535		)	(18,693		)	627			9,957		2,067			(1,469		)	(17,242		)
Financial instruments loss	15,929			10,279			2,027			4,722			—
Other loss	—			—			—			—			4,400
Other gain	—			—			(502		)	(2,000		)	—
Financial instruments (gain) loss																(46,215		)	12,296		15,929			10,279			2,027
Interest expense	13,882			14,145			—			—			—			43,268			27,364		13,882			14,145			—
	341,228			942,800			645,468			579,388			339,845			462,818			464,030		341,228			942,800			645,970

(Loss) on sale of business units and gain on acquisition	(44,385		)	929			—			—			—
Other (loss) gain																(12,886		)	—		(44,385		)	929			502
Interest income	1,209			2,368			1,369			2,856			2,174			696			2,086		1,209			2,368			1,369
Income (loss) from continuing operations before income taxes	37,330			(650,234		)	(368,088		)	(17,134		)	309,284
Income (loss) before income taxes																95,975			151,487		37,330			(650,234		)	(368,088		)

Current income tax expense	24,322			20,122			15,383			92,865			157,126			17,058			43,903		24,322			20,122			15,383
Deferred income tax expense (recovery)	44,716			(204,791		)	(115,442		)	34,350			(28,865		)	40,227			4,968		44,716			(204,791		)	(115,442		)
	69,038			(184,669		)	(100,059		)	127,215			128,261			57,285			48,871		69,038			(184,669		)	(100,059		)

(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
Net Income (Loss)																$	38,690		$	102,616	$	(31,708	)	$	(465,565	)	$	(268,029	)

(Loss) Income per Share
Income (Loss) per Share
Basic																$	0.10		$	0.26	$	(0.08	)	$	(1.45	)	$	(0.94	)
(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																$	0.10		$	0.26	$	(0.08	)	$	(1.45	)	$	(0.94	)

Balance Sheet Data
																As at December 31,
																2019			2018		2017			2016			2015
Cash and cash equivalents																$	8,301		$	51,040	$	12,326		$	25,175		$	145,342
Working capital (deficiency)																91,347			33,145		(11,724		)	(23,344		)	160,449
Oil and gas properties																1,569,743			1,310,026		1,094,029			1,060,093			780,360



Deferred tax asset - long-term	44,003	45,437	57,310	1,611	3,241
Total assets	2,044,664	1,676,584	1,429,619	1,367,896	1,146,118
Long-term debt	700,459	399,415	256,542	197,083	—
Deferred tax liability - long-term	59,762	23,419	28,417	107,230	34,592
Total long-term liabilities	812,713	477,454	336,315	353,880	70,485
Shareholders’ equity	1,032,610	1,029,750	936,335	858,987	1,001,642


◦•	~~Proved reserves increased by 11% to 59 MMBOE at year-end 2017, up from 53 MMBOE at year-end 2016~~ EBITDA⁽¹⁾ was $364.3 million compared with $376.7 million in 2018


◦•	~~Probable reserves increased by 25% to 55 MMBOE at year-end 2017, up from 44 MMBOE at year-end 2016~~ Adjusted EBITDA⁽¹⁾was $325.9 million compared with $375.9 million in 2018


•	Funds flow from operations⁽¹⁾ decreased by 11% to $272.4 million ($0.72 per share basic and diluted) compared with $306.4 million ($0.78 per share basic and diluted) in 2018, consistent with the average Brent price decreasing 11% from 2018


•	~~Operating netback~~⁽²⁾General and administrative ("G&A") expenses before stock-based compensation per BOE for ~~2017 was $29.43~~2019 increased by 5% to $3.13 per BOE ~~51% higher~~ compared ~~with 2016.~~to 2018


•	~~Funds flow from operations~~⁽²⁾ ~~for 2017 increased by 110%~~In November, 2019, we extended the maturity of our credit facility to ~~$220.2 million compared with 2016.~~November 10, 2022



(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		—		$	—


•	We are undertaking the NaturAmazonas project over the course of seven years, commencing in 2017. This project alone is expected to sequester approximately 8.7 million tons of CO₂ over its lifetime


	Fourth Quarter			Third Quarter			Fourth Quarter			Year Ended December 31,									Year Ended December 31,
(Thousands of U.S. Dollars)	2017			2017			2016			2017			2016			2015			2019			2018			2017
Net income (loss)	$	(40,802	)	$	3,130		$	(127,355	)	$	(31,708	)	$	(465,565	)	$	(268,029	)
Net Income (loss)																			$	38,690		$	102,616		$	(31,708	)
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			225,033			197,867			131,335
Asset impairment	275			787			146,934			1,514			616,649			323,918			—			—			1,514
Deferred tax expense (recovery)	8,052			13,760			(38,589		)	44,716			(204,791		)	(115,442		)
Deferred tax expense																			40,227			4,968			44,716
Stock-based compensation expense	4,840			1,752			1,959			9,775			6,339			2,733			1,430			8,299			9,775
Amortization of debt issuance costs	547			643			2,878			2,415			5,691			—			3,376			3,183			2,415
Non-cash lease expense																			1,806			—			—
Lease payments																			(1,969		)	—			—
Cash settlement of RSUs	(30		)	(33		)	(24		)	(564		)	(1,234		)	(1,392		)	—			(360		)	(564		)
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
Unrealized foreign exchange loss																			1,803			11,511			837
Financial instruments (gain) loss																			(46,215		)	12,296			15,929
Cash settlement of financial instruments	45			302			—			1,563			438			(3,749		)	(3,273		)	(33,931		)	1,563
Loss on sale of business units and (gain) on acquisition	35,309			—			10,783			44,385			(929		)	—
Other gain	—			—			—			—			—			(502		)
Loss on redemption of Convertible Notes																			11,501			—			44,385
Funds flow from operations (non-GAAP)	$	69,123		$	55,128		$	36,186		$	220,197		$	104,984		$	107,570		$	272,409		$	306,449		$	220,197



DD&A expenses	21.16			12		18.88		40		13.48
Asset impairment	—			—		—		(100	)	0.16
G&A expenses before stock-based compensation	3.13			5		2.99		(2	)	3.06
G&A stock-based compensation expense	0.13			(83	)	0.77		(19	)	0.95
Severance expenses	0.17			(26	)	0.23		77		0.13
Equity tax	—			—		—		(100	)	0.13
Foreign exchange loss	0.06			(94	)	0.95		352		0.21
Financial instruments (gain) loss	(4.35)			(472	)	1.17		(29	)	1.64
Interest expense	4.07			56		2.61		83		1.43
	24.37			(12	)	27.60		30		21.19

Other loss	(1.21		)	100		—		(100	)	(4.56		)
Interest income	0.07			(65	)	0.20		67		0.12

Income before income taxes	9.02			(38	)	14.45		280		3.80

Current income tax expense	1.60			(62	)	4.19		68		2.50
Deferred income tax expense	3.78			704		0.47		(90	)	4.59
	5.38			15		4.66		(34	)	7.09
Net Income (loss)	$	3.64		(63	)	$	9.79	398		$	(3.29	)



	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	%



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



	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


(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		Fourth quarter 2019 compared with third quarter 2019			% change		Fourth quarter 2019 compared with fourth quarter 2018			% change		Year ended December 31, 2019 compared with year ended December 31, 2018			% change
Net income (loss) for the comparative period	$	3,130				$	(127,355	)			$	(465,565	)
Net (loss) income for the comparative period																$	(28,833	)			$	(10,840	)			$	102,616
Increase (decrease) due to:
Sales volumes	2,732					5,857					32,161					463					(14,331		)			9,037
Prices	20,679					29,708					100,304					(5,020		)			5,627					(51,485		)
Expenses:
Operating	(4,082		)			(6,931		)			(22,944		)
Cash operating expenses, excluding stock-based compensation expense																(2,364		)			(4,348		)			(30,999		)
Workover																(114		)			(2,578		)			(6,681		)
Transportation	403					1,823					6,669					(1,054		)			3,736					8,593
Cash G&A and RSU settlements, excluding stock-based compensation expense	(396		)			3,341					(1,690		)			(873		)			5,602					(1,571		)
Transaction	—					—					7,325
Severance	1,041					(103		)			32					(549		)			(343		)			590
Interest, net of amortization of debt issuance costs	426					505					(3,013		)			(447		)			(5,575		)			(15,711		)
Realized foreign exchange	(36		)			1,190					(1,270		)
Realized foreign exchange loss (gain)																1,882					(327		)			(378		)
Settlement of financial instruments	(257		)			45					1,125					(68		)			6,764					30,658
Other loss																(1,385		)			(1,385		)			(1,385		)
Current taxes	(6,467		)			(2,358		)			(4,200		)			(86		)			4,544					26,845
Equity tax	—					45					1,874
Other	(48		)			(185		)			(1,160		)
Net lease payments																357					74					(163		)
Interest Income																(94		)			72					(1,390		)
Net change in funds flow from operations⁽¹⁾ from comparative period	13,995					32,937					115,213					(9,352		)			(2,468		)			(34,040		)
Expenses:
Depletion, depreciation and accretion	(4,114		)			(3,596		)			8,200					(10,791		)			(434		)			(27,166		)
Asset impairment	512					146,659					615,135
Deferred tax	5,708					(46,641		)			(249,507		)			(3		)			(3,389		)			(35,259		)
Amortization of debt issuance costs	96					2,331					3,276					(13		)			52					(193		)
Loss on convertible notes																11,109					(196		)			(11,501		)
Net Lease Payments																(357		)			(74		)			163
Stock-based compensation, net of RSU settlement	(3,091		)			(2,875		)			(4,106		)			(346		)			(12,516		)			6,509
Financial instruments gain or loss, net of financial instruments settlements	(19,208		)			(12,730		)			(6,775		)			55,678					42,017					27,853
Unrealized foreign exchange	(2,521		)			(5,006		)			(2,265		)			9,912					14,852					9,708
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					55,837					37,844					(63,926		)
Net loss for the current period	$	(40,802	)	1,404	%	$	(40,802	)	68	%	$	(31,708	)	93	%
Net income for the current period																$	27,004		(194	)%	$	27,004		349	%	$	38,690		62	%



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



	Number of wells (Gross and Net)
Colombia
Development	25.0
Exploration	6.0
Service	5.0
Total	36.0


	Total		2018		2019-2020		2021-2022		2022 and beyond		Total		2020		2021-2022		2023-2024		2025 and beyond
(Thousands of U.S. Dollars)
Revolving credit facility	$	148,000	$	—	$	148,000	$	—	$	—	$	118,000	$	—	$	118,000	$	—	$	—
5% Convertible Senior Notes due 2021	115,000		—		—		115,000		—
6.25% Senior Notes											300,000		—		—		—		300,000
7.75% Senior Notes											300,000		—		—		—		300,000
Total long-term debt	263,000		—		148,000		115,000		—		718,000		—		118,000		—		600,000
Interest payments⁽¹⁾	34,116		11,144		21,534		1,438		—		289,090		46,070		91,572		84,000		67,448
Oil transportation services	10,895		3,842		7,053		—		—		3,211		3,211		—		—		—
Facility construction	27,006		5,446		10,907		10,653		—
Drilling, completions and seismic											21,409		7,602		13,669		39		99
Operating leases	4,554		1,840		2,507		207		—		5,679		2,708		2,971		—		—
Software and telecommunication	961		339		622		—		—
Finance leases											6,232		2,760		3,276		168		28
Total	$	340,532	$	22,611	$	190,623	$	127,298	$	—	$	1,043,621	$	62,351	$	229,488	$	84,207	$	667,575



	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



	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



(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


	Three Months Ended										Year Ended			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			March 31, 2019		June 30, 2019		September 30, 2019			December 31, 2019		December 31, 2019
Oil and natural gas sales	$	94,659	$	96,128		$	103,768	$	127,179		$	421,734		$	152,565	$	157,993	$	132,491		$	127,934	$	570,983

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

Net income (loss)	$	12,771	$	(6,807	)	$	3,130	$	(40,802	)	$	(31,708	)	$	1,979	$	38,540	$	(28,833	)	$	27,004	$	38,690

Net income (Loss) per share - Basic and Diluted	$	0.03	$	(0.02	)	$	0.01	$	(0.10	)	$	(0.08	)
Net income (loss) per share
Basic														$	0.01	$	0.10	$	(0.08	)	$	0.07	$	0.10
Diluted														$	0.01	$	0.10	$	(0.08	)	$	0.07	$	0.10