Edgar Filing: GRAN TIERRA ENERGY INC.

Document

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, 2018



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

For the transition period from __________ to __________

Commission file number 001-34018

GRAN TIERRA ENERGY INC.

(Exact name of registrant as specified in its charter)



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

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

(403) 265-3221

(Registrant’s telephone number, including area code)

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



Title of each class		Name of each exchange on which registered
Common Stock, par value $0.001 per share		NYSE American
		Toronto Stock Exchange
		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 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 every Interactive Data File required to be submitted 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 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. ý

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	Smaller reporting company o
	Emerging growth company o

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $0.9 billion.

On February 22, 2019, the 387,079,027 shares of the registrant’s Common Stock with $0.001 par value 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 2019 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2018.

Gran Tierra Energy Inc.

Annual Report on Form 10-K

Year Ended December 31, 2018

Table of Contents



		Page

PART I
Items 1 and 2.	Business and Properties	5
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	22
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Financial Data	26
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 8.	Financial Statements and Supplementary Data	50
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	83
Item 9A.	Controls and Procedures	83
Item 9B.	Other Information	85

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	85
Item 11.	Executive Compensation	85
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	85
Item 13.	Certain Relationships and Related Transactions, and Director Independence	86
Item 14.	Principal Accounting Fees and Services	86

PART IV
Item 15.	Exhibits, Financial Statement Schedules	86
Item 16.	Form 10-K Summary	92

SIGNATURES		92

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

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

GLOSSARY OF OIL AND GAS TERMS

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



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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(i) The area of the reservoir considered as proved includes:

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

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

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

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

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

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

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

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

Proved undeveloped reserves. In general, reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

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

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

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

PART I

Items 1 and 2. Business and Properties

General

Gran Tierra Energy Inc., together with its subsidiaries (“Gran Tierra”, “the Company”, “us”, “our”, or “we”), is a company focused on oil and gas exploration and production in Colombia. Our Colombian properties represented 100% of our proved reserves NAR at December 31, 2018. For the year ended December 31, 2018, 100% (year ended December 31, 2017 - 98%, and year ended December 31, 2016 - 97%) of our revenue and other income was generated in Colombia.

We were incorporated under the laws of the State of Nevada in June 2008 and changed our state of incorporation to the State of Delaware in October 2016. We made our initial acquisition of oil and gas producing and non-producing properties in Argentina in September 2005. Since then, we have acquired oil and gas producing and non-producing assets in Colombia, Peru, Argentina and Brazil. We sold our Argentina business unit in 2014. In 2016, we completed acquisitions of Petroamerica Oil Corp. (“Petroamerica”), PetroGranada Colombia Limited (“PGC”) and PetroLatina Energy Limited (“PetroLatina”). During 2017, we completed the sale of our assets in Brazil and Peru.

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

2018 Overview

Acquisitions and Dispositions

On October 1, 2018, the Company acquired the remaining 45% WI in the PUT-1 Block in the Putumayo Basin for cash consideration of $28.1 million.

On August 6, 2018, the Company acquired a working interest WI in the VMM-2 block in the Middle Magdalena Valley Basin for cash consideration of $17.0 million. On December 1, 2018, the Company acquired an additional working interest ("WI") in the VMM-2 block for cash consideration of $5.0 million.

On June 20, 2018, the Company acquired the remaining WI in the Alea 1848-A and 1947-C Blocks in the Putumayo Basin for cash consideration of $3.1 million.

Subsequent to December 31, 2018, the Company announced that it had entered into an agreement to acquire working interest and operatorship of the Suroriente Block, which would increase Gran Tierra's WI from 16% to 52%. In addition, the Company would acquire 50% WI in and operatorship of the Putumayo-8 Block, and 100% WI in the Llanos-5 Block. The purchase price for the acquisition is $104.2 million and is subject to certain adjustments and the satisfaction of certain customary conditions.

2018 Operational Highlights

During the year ended December 31, 2018, we incurred capital expenditures of $347.1 million, all of which were incurred in Colombia. In 2018, we drilled 5 exploration and 23 development wells.

We spud 5 exploration wells (two in Put-7, one in Sinu-3, one in Midas and one in Alea blocks). One of these wells was producing, three were in-progress and one was a dry well as at December 31, 2018.

We spud 23 development wells (15 in Midas, 5 in Chaza, one in Suroriente, one in Put-7 and one in La Paloma blocks). As at December 31, 2018, 19 of these wells were producing and 4 were in-progress.

Of the 4 wells in progress in Colombia as at December 31, 2017, three were producing and one was a dry well as at December 31, 2018.

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

2019 Outlook

Colombia remains our primary focus and represents 100% of the 2019 capital program. In December 2018, we announced our 2019 capital budget. On February 20, 2019, we announced the acquisitions of an additional 36.2% WI and operatorship in the Suroriente Block, 50%WI and operatorship in the PUT-8 Block and 100% WI in the LLA-5 Block and, as a result, have revised our 2019 capital budget as follows:



	Number of Wells (Gross)	Number of Wells (Net)	2019 Capital Budget ($ million)
Colombia
Development	26-30	25-29	130-135
Exploration	6-8	6-8	80-85
Facilities	—	—	85-90
Seismic and Studies	—	—	25-30
	32-38	31-37	320-340

Based on the midpoint of the updated guidance, the capital budget is forecasted to be approximately 65% directed to development and 35% to exploration. Approximately 25% of the 2019 capital program is expected to be directed to facilities, with approximately 50% of this investment expected to be dedicated to the ongoing facilities expansion at the Acordionero Field.

We expect our 2019 capital program to be fully funded by cash flows from operations.

Business Strategy

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

Oil and Gas Properties - Colombia

Acquisitions

On October 1, 2018, we acquired the remaining 45% WI in the PUT-1 Block in the Putumayo Basin for cash consideration of $28.1 million.

On August 6, 2018, we acquired a WI in VMM-2 in the Middle Magdalena Valley Basin for cash consideration of $17.0 million.On December 1, 2018, we acquired additional WI in the VMM-2 block for cash consideration of $5.0 million. As a result, our WI in VMM-2 represents 80%.

On June 20, 2018, we acquired the remaining WI in the Alea 1848-A and 1947-C Blocks in the Putumayo Basin for cash consideration of $3.1 million.

Subsequent to year-end, the Company announced that it had entered into an agreement to acquire working interest and operatorship of the Suroriente Block, which would increase Gran Tierra's WI from 16% to 52%. In addition, the Company would acquire 50% WI in and operatorship of the Putumayo-8 Block, and 100% WI in the Llanos-5 Block. The purchase price for the acquisition is $104.2 million and is subject to certain adjustments and the satisfaction of certain customary conditions.

Excluding blocks subject to relinquishment, we have interests in 27 blocks in Colombia and are the operator on 23 of those blocks.

Exploration Blocks & Commitments

The following table provides a summary of our exploration commitments for certain blocks as at December 31, 2018:



Basin	Block	Current Phase	Remaining Commitments, Current Phase
Putumayo	Alea 1848-A	3 & 4	43.8 km² 3D seismic, 1 exploration well
Putumayo	Alea 1947-C	2*	1 exploration well
Putumayo	PUT-1	2*	2 exploration wells
Putumayo	PUT-2	2**	3 exploration wells
Putumayo	PUT-4	1	30 km²3D seismic
Putumayo	PUT-7	2	2 exploration wells
Putumayo	PUT-10	1*	73 km 2D seismic, 2 exploration wells
Putumayo	PUT-25	1	20.7 km²3D seismic
Putumayo	PUT-31	1	200 km² 3D seismic,1.9 km 2D seismic,1 exploration well
Llanos	El Porton	5	1 exploration well
Llanos	LLA-1	1**	97.5 km² 3D seismic, 1 exploration well
Llanos	LLA-10	1*	1 exploration well
Llanos	LLA-22	1 & 2*	125 km² 3D seismic, 1 exploration well
Llanos	LLA-53	1*	100 km² 3D seismic, 2 exploration wells (pending approval to transfer commitments to PUT-4 and PUT-7)
Llanos	LLA-70	1**	163.4 km² 3D seismic, 1 exploration well
Caguan-Putumayo	Tinigua	2*	1 exploration well

*As of February 22, 2019, suspended due to either licensing restrictions or social reasons

** As of February 22, 2019, 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 Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) contracts have royalties that are based on a sliding scale described in Law 756 of 2002. 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, 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%.

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

An additional royalty (the “HPR royalty”) applies on exploration and production contracts signed under the ANH oil regulatory regime in 2004 and onwards when cumulative gross production from an Exploitation Area is greater than five MMbbl and reference prices exceed the trigger price defined in the contract. For exploration and production contracts awarded in the 2010, 2012 and 2014 Colombia Bid Rounds, the HPR royalty will apply once the production from the area governed by the contract, rather than any particular Exploitation Area designated under the contract, exceeds five MMbbl of cumulative production. At December 31, 2018, 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 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' factor payment to be deducted from production revenue prior to the royalty being paid to a third party. Pursuant to the terms of the agreement by which the interests in the Putumayo-1 Block were acquired, a 3% royalty on production from the Putumayo-1 Block is payable to a third party. The terms of the royalty do not allow for any costs, royalties and 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.

Estimated Reserves

Our 2018 reserves were independently prepared by McDaniel International Inc. (“McDaniel”), a wholly owned subsidiary of McDaniel & Associates. McDaniel & Associates was established in 1955 as an independent Canadian consulting firm and has been providing oil and gas reserves evaluation services to the world's petroleum industry for the past 60 years. They have internationally recognized expertise in reserves evaluations, resource assessments, geological studies, and acquisition and disposition advisory services. McDaniel's office is located in Calgary, Canada. The technical person primarily responsible for the preparation of our reserves estimates at McDaniel meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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

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

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

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

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

The following table sets forth our estimated reserves NAR as of December 31, 2018:



	Oil	Natural Gas	Oil and Natural Gas
Reserves Category	(Mbbl)	(MMcf)	(MBOE)
Proved
Total proved developed reserves	36,805	1,253	37,014
Total proved undeveloped reserves	17,117	929	17,272
Total proved reserves	53,922	2,182	54,286

Probable
Total probable developed reserves	9,832	386	9,896
Total probable undeveloped reserves	51,559	886	51,707
Total probable reserves	61,391	1,272	61,603

Possible
Total possible developed reserves	13,480	458	13,556
Total possible undeveloped reserves	35,216	949	35,374
Total possible reserves	48,696	1,407	48,930

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	$	61.16
Natural Gas ($/Mcf) - Colombia	$	3.61
ICE Brent - average of the first day of each month price for the 12-month period	$	72.08

These prices should not be interpreted as a prediction of future 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, 2018, we had total proved undeveloped reserves NAR of 17.3 MMBOE (December 31, 2017 - 19.6 MMBOE), which were 100% in Colombia (December 31, 2017 – 100%). Approximately 43%, 10% , 11% and 9% of proved undeveloped reserves are located in our Acordionero, Costayaco, Cumplidor and Moqueta Fields, respectively, in Colombia. None of our proved undeveloped reserves at December 31, 2018 have remained undeveloped for five years or more since initial disclosure as proved reserves and we have adopted a development plan which indicates that the proved undeveloped reserves are scheduled to be drilled within five years of initial disclosure as proved reserves.

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



	Colombia - Oil Equivalent (MMBOE)
Balance, December 31, 2017	19.6
Acquisitions	0.7
Converted to proved producing	(12.9	)
Discoveries and extensions	6.4
Technical revisions	3.5
Balance, December 31, 2018	17.3

In 2018, we converted 12.9 MMBOE, or 66%, of 2017 proved undeveloped reserves to developed status. In 2018, we made investments, consisting solely of capital expenditures, of $92.7 million in Colombia associated with the development of proved undeveloped reserves.

Production, Revenue and Price History

Certain information concerning production, prices, revenues and operating expenses for the three years ended December 31, 2018 is set forth in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the Unaudited Supplementary Data provided following our Financial Statements in Item 8, which information is incorporated by reference here.

The following table presents oil and NGL production NAR from our Costayaco ("CYC"), Moqueta ("MQT") and Acordionero ("ACR") Fields for the three years ended December 31, 2018:



	Year Ended December 31,
	2018						2017						2016
	CYC		MQT		ACR		CYC		MQT		ACR		CYC		MQT		ACR
Oil and NGL's, bbl	2,244,497		1,020,673		5,469,072		3,173,659		1,550,344		3,131,577		3,975,842		2,091,361		648,518
Average sales price of oil and NGL's per bbl	$	58.19	$	59.87	$	57.64	$	43.55	$	45.05	$	43.90	$	33.52	$	32.86	$	35.87
Operating expenses of oil and NGL's per bbl	$	22.23	$	20.47	$	11.22	$	11.70	$	15.27	$	10.34	$	13.71	$	10.50	$	8.00

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, 2018, 2017 or 2016. 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.



	2018		2017		2016
	Gross	Net	Gross	Net	Gross	Net

Exploration
Productive	1.00	1.00	2.00	1.55	2.00	2.00
Dry	1.00	0.51	—	—	—	—
In Progress	3.00	3.00	2.00	2.00	1.00	1.00
Development
Productive	19.00	18.16	17.00	13.63	7.00	7.00
Service	—	—	2.00	2.00	2.00	2.00
Dry	—	—	—	—	1.00	1.00
In Progress	4.00	4.00	2.00	1.70	3.00	3.00
Total Colombia	28.00	26.67	25.00	20.88	16.00	16.00

Of the four wells in progress in Colombia as at December 31, 2017, three were producing and one was a dry well as at December 31, 2018.

In 2018, we also continued pressure maintenance projects in the Costayaco and Moqueta Fields in Colombia.

Well Statistics

The following table sets forth our productive wells as of December 31, 2018:



	Oil Wells
	Gross	Net
Colombia⁽¹⁾	167.0	124.0
	167.0	124.0

⁽¹⁾ Includes 21.0 gross and 16.2 net water injector wells and 67.0 gross and 62.7 net wells with multiple completions.

Developed and Undeveloped Acreage

At December 31, 2018, our acreage was located 100% in Colombia. The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2018:

Developed

Undeveloped

Total

Gross

Net

Gross

Net

Gross

Net

Colombia⁽¹⁾

334,112

208,537

1,519,573

1,351,980

1,853,685

1,560,517

⁽¹⁾Excludes our interest in 4 blocks with a total of 0.5 million net acres for which government approval of relinquishments or sale was pending at December 31, 2018.

Research and Development

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

Marketing and Major Customers

Colombia

Our oil reserves and production in Colombia are mainly located in the Middle Magdalena Valley (“MMV”) and Putumayo Basin. In MMV, our focus is on the Acordionero Field, where production is approximately 19° API and represented 52% of our production in 2018. The Putumayo production (as defined below) is approximately 29° API and represented 42% of our production in 2018.

We have entered into numerous agreements to sell oil produced in the Chaza and Guayuyaco Blocks (the “Putumayo production”). These agreements are subject to renegotiation for terms between three to twelve months and generally contain mutual termination provisions with 90 days' notice. The volume of crude oil does not include the volume of oil corresponding to royalties taken in kind, but does include volumes relating to HPR royalties.

In 2018, approximately 20% of our Putumayo production was sold to Ecopetrol, with the remainder sold to other parties. The Ecopetrol agreement will expire November 30, 2019. We deliver our oil to Ecopetrol through our transportation facilities which include pipelines, gathering systems and through the transportation and logistics assets of Cenit Transporte y Logistica de Hidrocarburos S.A.S (“CENIT”), a wholly-owned subsidiary of Ecopetrol. The point of sale of our Putumayo production to Ecopetrol is the Port of Tumaco on the Pacific coast of Colombia. In the event of pipeline disruptions, the point of sale is the Port of Esmeraldas (Ecuador) where sales are to other third parties.

We have entered into ship and pay transportation agreements (the “Transportation Agreements”) with CENIT. These agreements will expire November 30, 2019. Pursuant to the Transportation Agreements we pay a transportation tariff and transportation tax for the transportation of the Putumayo production from the Putumayo Basin to the Port of Tumaco. Pursuant to the Transportation Agreements, Gran Tierra Energy Colombia Ltd. has the right to transport up to 10,000 bopd, subject to availability of capacity, (1) from Santana Station to CENIT’s facility at Orito through CENIT’s Mansoya - Orito Pipeline (“OMO”), and (2) from CENIT’s facility at Orito to the Port of Tumaco through CENIT’s Orito - Tumaco Pipeline (“OTA”). Generally, under these agreements,

CENIT is liable (subject to specified limitations) for pollution clean-up costs resulting from incidents during transportation. The cost of oil lost during transportation is shared by the parties that ship oil on the pipeline, in proportion to their share of total volumes shipped.

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

Putumayo production is also sold to multiple other parties, in addition to Ecopetrol. Other sales in Putumayo are generally delivered at the wellhead. Oil is delivered and sold at the Costayaco battery and Santana station and loaded into trucks. When oil is loaded into trucks there are multiple evacuation routes. For oil delivered via truck to Amazonas, Oleoducto de Crudos Pesados (OCP) Ecuador S.A. Ecuador, the sales point is the Port of Esmeraldas and it is sold as Chaza blend 29 API.

Trucking options for Putumayo include, but are not limited to: (1) from Santana Station to OCP’s Amazonas Station truck offloading facility, a distance of approximately 128 kilometers; and (2) from the Costayaco Field to OCP’s Amazonas Station truck offloading facility, a distance of approximately 178 km.

In MMV, the Acordionero Field production is currently sold to Trafigura. We truck this volume 530 kilometers to the buyer at Puerto Bahia, Cartagena Bay and 165 kilometers to the buyer at Impala Terminals, Barrancabermeja. We are evaluating the construction of a pipeline tie in at the Acordionero Field, which is expected to provide us with access to the Port of Coveñas for future sales at the export terminal. Production from the minor fields in MMV is sold at the wellhead on a contract which will expire April 30, 2019.

Trucking options for Llanos include: (1) from the Garibay Jilguero Field to facilities at Cusiana Station, a distance of approximately 77 kilometers; and (2) from the Llanos 22 Ramiriqui Field to facilities at Cusiana Station, a distance of approximately 45 kilometers.

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

Competition

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

Geographic Information

We have one reportable segment based on geographic organization, Colombia. Prior to the sale of our Brazil business unit effective June 30, 2017 and our Peru business unit effective December 18, 2017, Brazil and Peru were reportable segments. Long lived assets are Property, Plant and Equipment, which includes all oil and gas assets, furniture and fixtures, automobiles and computer equipment. No long lived assets are held in our country of domicile, which is the United States of America. “All Other” assets include assets held by our corporate head office in Calgary, Alberta, Canada. Because all of our exploration and development operations are in Colombia, we face many risks associated with these operations. See Item 1A. “Risk Factors” for risks associated with our foreign operations.

Regulation

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

Colombia Administration

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

In Colombia, the ANH is the administrator of the hydrocarbons in the country and therefore is responsible for regulating the Colombian oil and gas industry, including managing all exploration lands. Since 2003, Ecopetrol, the Colombian national oil company, has been a public company owned in majority by the state with the main purpose of exploring and producing hydrocarbons similar to any other oil company. In addition, Ecopetrol is a major purchaser and marketer of oil in Colombia and operates the majority of the oil transportation infrastructure in the country.

The ANH uses an exploration risk contract, or the Exploration and Production Contract, which provides full risk/reward benefits for the contractor. Under the terms of this contract, the successful operator retains the rights to all reserves, production and income from any new exploration block, subject to existing royalty and tax regulations. Each contract contains an exploration phase and a production phase. The exploration phase contains a number of exploration periods and each period has an associated work commitment. The production phase lasts a number of years (usually 24) from the declaration of a commercial hydrocarbon discovery.

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

Environmental Compliance

Our activities are subject to laws and regulations governing environmental quality and pollution control in the countries where we maintain operations. Our activities with respect to exploration, drilling, production and facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil and other products, are subject to stringent environmental regulation by regional and federal authorities in Colombia. Such regulations relate to environmental impact studies, the discharge of pollutants into air and water, water use and management, the management of non-hazardous and hazardous waste, including its transportation, storage, and disposal, permitting for the construction of facilities, recycling requirements and reclamation standards, and the protection of certain plants and animal species as well as cultural resources and areas inhabited by indigenous peoples, among others. Risks are inherent in oil and gas exploration, development and production operations. These risks include blowouts, fires, or spills. Significant costs and liabilities may be incurred in connection with environmental compliance issues. Licenses and permits required for our exploration and production activities may not be obtainable on reasonable terms or on a timely basis, which could result in delays and have an adverse effect on our operations. Spills and releases into the environment of petroleum products can result in remediation costs and liability for damages. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. Moreover, violations of environmental laws and regulations can result in the issuance of administrative, civil, or criminal fines and penalties, as well as orders or injunctions prohibiting some or all of our operations in affected areas. In addition, indigenous groups or other local organizations could oppose our operations in their communities, potentially resulting in delays which could adversely affect our operations. Governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. We do not expect that the cost of compliance with regional and federal provisions, which have been enacted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment or natural resources, will be material to us.

We have implemented a company wide web-based reporting system which allows us to track incidents and respective corrective actions and associated costs. We have a Corporate Health, Safety, and Environmental Management Policy and Plan as well as a Corporate Environmental Management Plan ("EMP"). The EMP is based on the environmental performance standards of the World

Bank/IFC and reflects best industry practices. We have and Environmental Management System which is ISO14001:2015 certified representing compliance with internationally recognized industry best practice, as well as an environmental risk management program and robust waste management procedures. Air and water testing occur regularly and environmental contingency plans have been prepared for all sites and transportation of oil. We have a regular quarterly comprehensive reporting system, reporting to executive management as well as a committee of the Board. We have a schedule of internal and external audits and routine checking of practices and procedures and conduct emergency response exercises.

Employees

At December 31, 2018, we had 334 full-time employees (December 31, 2017 - 324): 94 located in the Calgary corporate office, and 240 in Colombia (173 staff in Bogota and 67 field personnel). None of our employees are represented by labor unions, and we consider our employee relations to be good.

Available Information

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

In addition, the SEC maintains a website (www.sec.gov) where you may obtain reports, proxy and information statements and other information regarding us.

Item 1A. Risk Factors

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

Substantially all of our revenues are derived from the sale of oil, the current and forward contract price which is based on world demand, supply, weather, pipeline capacity constraints, inventory storage levels, geopolitical unrest and other factors, all of which are beyond our control. Historically, the market for oil has been volatile, and the market is likely to continue to be volatile in the future. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contracts with purchasers with prescribed deductions for transportation and quality differentials. These differentials can change over time and have a detrimental impact on realized prices.

Future decreases in the prices of oil or sustained low prices may have a material adverse effect on our financial condition, the future results of our operations (including rendering existing projects unprofitable), financing available to us, and quantities of reserves recoverable on an economic basis, as well as the market price for our securities.

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

We make estimates of oil and natural gas reserves, upon which we base our financial projections and capital expenditure plans. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. Wells that are drilled may not achieve the results expected. Economic factors beyond our control, such as world oil prices, interest rates, inflation, and exchange rates, will also impact the quantity and value of our reserves.

The process of estimating oil and natural gas reserves is complex, and requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserves estimates are inherently imprecise. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. When producing an estimate of the amount of oil that is recoverable from a particular reservoir, probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. Estimates of probable and possible reserves are by their nature much more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

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

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

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

Exploration, development and production costs (including transportation and workover costs), marketing costs (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and natural gas that we produce. These costs are subject to fluctuations and variations in the areas in which we operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations.

Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

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

Oil and natural gas exploration involves a high degree of operational and financial risk. These risks are more acute in the early stages of exploration, appraisal and development. It is difficult to predict the results and project the costs of implementing an exploratory drilling program due to the inherent uncertainties and costs of drilling in unknown formations and encountering various drilling conditions, such as unexpected formations or pressures, premature decline of reservoirs, the invasion of water into producing formations, tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.

Oil and natural gas exploration, development and production operations are subject to the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards. Such risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property or the environment, as well as personal injury to our employees, contractors or members of the public.

Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects.

Although we maintain well control and liability insurance in an amount that we consider prudent and consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. In either event we could incur significant costs.

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

Our base capital program for 2019 is $320 to $340 million for exploration and development. This does not include the cost of any acquisitions. We expect to finance our 2019 capital program primarily through cash flows from operations. Funding this program from cash flow from operations relies in part on Brent oil prices being $65 per barrel, or higher.

If cash flows from operations, cash on hand and available capacity under our credit facility are not sufficient to fund our capital program, we may be required to seek external financing or to delay or reduce our exploration and development activities, which could impact production, revenues and reserve growth.

If we require additional capital, we may pursue sources of capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be able to access capital on favorable terms or at all. If we do succeed in raising additional capital, future financings may be dilutive to our shareholders, as we could issue additional shares of common stock or other equity to investors. In addition, debt and other mezzanine financing may involve a pledge of assets, require covenants that would restrict our business activities, and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertibles and warrants, which would adversely impact our financial results.

Our ability to obtain needed financing may be impaired by factors such as weak capital markets (both generally and for the oil and gas industry in particular), the location of our oil and natural gas properties in Colombia, low or declining prices of oil and natural gas on the commodities markets, and the loss of key management. Further, if oil or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. Some of the contractual arrangements governing our exploration activity may require us to commit to certain capital expenditures, and we may lose our contract rights if we do not have the required capital to fulfill these commitments. If the amount of capital we are able to raise from financing activities, together with our cash flow from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our activities), we may be required to curtail our operations.

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

The borrowing base under our revolving credit facility is currently $300 million. Our borrowing base is redetermined by the lenders twice per year. Our borrowing base may decrease as a result of a decline in oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for any other reason. We cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. In the event of a decrease in our borrowing base, we could be required to repay any indebtedness in excess of the redetermined borrowing base, which could deplete cash flow from operations or require additional financing. Further, our borrowing base is made available to us subject to the terms and covenants of our revolving credit facility, including compliance with the ratios and other financial covenants of such facility, and a failure to comply with such ratios or covenants could force us to repay a portion of our borrowings and suffer adverse financial impacts.

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

All of our reserves and production are currently located in Colombia; however, we may eventually expand to other countries. Exploration and production operations are subject to legal, social, political and economic uncertainties, including terrorism, military repression, social unrest and activism, strikes by local or national labor groups, interference with private contract rights, extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. When such disruptions occur, they may adversely impact our operations and threaten the economic viability of our projects or our ability to meet our production targets.

Colombia has experienced and may in the future experience political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including but not limited to: the imposition of additional taxes; nationalization; changes in energy or environmental policies or the personnel administering them; changes in oil and natural gas pricing policies; and royalty changes or increases. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets or renegotiation or nullification of existing concessions and contracts. In 2018, there was a national election in Colombia, resulting in a new country president who may in the future take positions on oil and gas issues that are contrary to our interests. Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Colombia are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.

We are vulnerable to risks associated with geographically concentrated operations

The vast majority of our production comes from three fields. For the year ended December 31, 2018, the Acordionero, Costayaco and Moqueta Fields collectively generated 82% of our production and at December 31, 2018, these three fields accounted for 89% of our proved reserves. As a result of this concentration, we may be disproportionately exposed to the impact of, among other things, regional supply and demand factors including limitations on our ability to most profitably sell or market our oil and natural

gas to a smaller pool of potential buyers, delays or interruptions of production from wells in these areas caused by governmental regulation, community protests, guerrilla activities, processing or transportation capacity constraints, continued authorization by the government to explore and drill in these areas, severe weather events and the availability of drilling rigs and related equipment, facilities, personnel or services. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

We rely on local infrastructure and the availability of transportation for storage and shipment of our products. This infrastructure, including storage and transportation facilities, is less developed than that in North America and may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. Further, we operate in remote areas and may rely on helicopters, boats or other transportation methods. Some of these transport methods may result in increased levels of risk, including the risk of accidents involving serious injury or loss of life, and could lead to operational delays which could affect our ability to add to our reserve base or produce oil and could have a significant impact on our reputation or cash flow. Additionally, some of this equipment is specialized and may be difficult to obtain in our areas of operations, which could hamper or delay operations, and could increase the cost of those operations.

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

To enjoy the support and trust of local populations and governments, we must demonstrate a commitment to providing local employment, training and business opportunities; a high level of environmental performance; open and transparent communication; and a willingness to discuss and address community issues including community development investments that are carefully selected, not unduly costly and bring lasting social and economic benefits to the community and the area. Improper management of these relationships could lead to a delay or suspension in operations, loss of license or major impact to our reputation in these communities, which could adversely affect our business. We cannot ensure that such issues or disruptions will not be experienced in the future and we cannot predict their potential impacts, which may include delays or loss of production, standby charges, stranded equipment, or damage to our facilities. In addition, we must comply with legislative requirements for prior consultation of communities and ethnic groups who are affected by our proposed projects in Colombia. Notwithstanding our compliance with these requirements, we may be sued by such communities through a writ for protection of tutela in the Colombian courts for enhanced consultation, potentially leading to increased costs, operational delays and other impacts. In addition, several areas in Colombia have conducted Popular Consultations, essentially referendums, on extractive industries. The referendums were organized by opponents of the mining or oil and natural gas industries. To this point all have passed with a large majority voting to prohibit extractive industry activity in the particular region, but it remains unclear to what extent such results can impact the exercise of mineral rights conferred by the national government. We believe that some groups are seeking to pose a referendum question in the Yopal/Casanare area in 2019, potentially adversely affecting our ability to drill our Prosperidad-1 exploration prospect and increasing the costs associated with such development plan. It is not yet clear if they will succeed in gaining the requisite number of signatures to conduct the referendum or whether all of the other legal and procedural requirements will be satisfied by the proponents.

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

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous licenses, permits, approvals and certificates, including environmental and other operating permits. We may not be able to obtain, sustain or renew such licenses and permits on a timely basis or at all. We may also have licenses and permits rescinded or not be able to renew expiring licenses and permits. Failure or delay in obtaining or maintaining regulatory approvals or permits could have a material adverse effect on our ability to develop and explore on our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. Loss of permits for existing drilling, water injection or other activities necessary for production may result in a decline in our production levels and revenues or damage to the well structure. Regulations and policies relating to these licenses and permits may change, be implemented in a way that we do not currently anticipate or take significantly greater time to obtain. There can be no assurance that future political conditions in Colombia will not result in changes to policies with respect to foreign development and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities.

As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations.

Guerilla activity and security concerns in Colombia may disrupt our operations

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

Colombia also has a history of security problems. Our efforts to ensure the security of our physical assets may not be successful and there can also be no assurance that we can maintain the safety of our or our contractors' field personnel and our Bogota head office personnel or operations in Colombia or that this violence will not adversely affect our operations in the future and cause significant loss. If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected.

Environmental regulation and risks may adversely affect our business

Environmental regulation is stringent and the costs and expenses of regulatory compliance are increasing. All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to an extensive suite of international conventions and national and regional laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances used or produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal fines and penalties. Our operations create the risk of significant environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water or for certain other environmental impacts. There is uncertainty around the impact of environmental laws and regulations, including those presently in force and those expected to be proposed in the future. We cannot predict how future environmental laws will be interpreted, administered or enforced, but more stringent laws or regulations or more vigorous enforcement policies could in the future require material expenditures by us for the installation and operation of compliant systems; therefore it is impossible at this time to predict the nature and impact of those requirements on our company however they may have a material adverse impact on our business.

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

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

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

Foreign currency exchange rate volatility may affect our financial results

We sell our oil and natural gas production under agreements that are denominated mainly in U.S. dollars. Many of the operational and other expenses we incur, including current and deferred tax liabilities in Colombia, are denominated in Colombian pesos. Most of our administration costs in Canada are incurred in Canadian dollars. As a result, we are exposed to translation risk when local currency financial statements are translated to U.S. dollars, our functional currency. An appreciation of local currencies can

increase our costs and negatively impact our results from operations. Because our Consolidated Financial Statements are presented in US$, we must translate revenues, expenses and income, as well as assets and liabilities, into US$ at exchange rates in effect during or at the end of each reporting period. We are also exposed to transaction risk on settlement of payables and receivables denominated in foreign currency.

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

We are subject to anti-bribery laws in the United States, Canada and Colombia and will be subject to similar laws in other jurisdictions where we may operate in the future. We may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, international organizations, or private entities. As a result, we face the risk of unauthorized payments or offers of payments by employees, contractors, agents, and partners of ours or our subsidiaries or affiliates, given that these parties are not always subject to our control or direction. It is our policy to prohibit these practices. However, our existing safeguards and any future improvements to those measures may prove to be less than effective or may not be followed, and our employees, contractors, agents, and partners may engage in illegal conduct for which we might be held responsible. A violation of any of these laws, even if prohibited by our policies, may result in criminal or civil sanctions or other penalties (including profit disgorgement) as well as reputational damage and could have a material adverse effect on our business and financial condition.

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

Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States. Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future. A finding by the President that Colombia has failed demonstrably to meet its obligations under international counter-narcotic agreements may result in the imposition of economic and trade sanctions on Colombia which could result in adverse economic consequences in Colombia including potentially threatening our ability to obtain necessary financing to develop our Colombian properties, and could further heighten the political and economic risks associated with our operations there.

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

We use digital technologies and software programs to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, as well as to process and record financial and operating data. We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexities of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, and global competition for oil and gas resources make certain information attractive to thieves. Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs and therefore it is critical to our business that our facilities and infrastructure remain secure. While we have implemented strategies to mitigate impacts from these types of events, we cannot guarantee that measures taken to defend against cybersecurity threats will be sufficient for this purpose. The ability of the information technology function to support our business in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected interruptions cannot be fully tested and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of the breach or disaster. In that event, key information and systems may be unavailable for a number of days or weeks, leading to our inability to conduct business or perform some business processes in a timely manner. Moreover, if any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.

Our employees have been and will continue to be targeted by parties using fraudulent “spoof” and “phishing” emails to misappropriate information or to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. Despite our efforts to mitigate “spoof” and “phishing” emails through policies and education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure.

Regulations related to emissions and the impact of any changes in climate could adversely impact our business

Governments around the world have become increasingly focused on regulating greenhouse gas (“GHG”) emissions and addressing the impacts of climate change in some manner. Colombia has enacted legislation related to GHG emissions and has also passed legislation requiring the country to generate 77% of its electric energy from renewable resources and reduce net deforestation in the Amazon to zero by 2020. In addition, Colombia has established the National Energy Efficiency Program, which calls for electric utilities, oil and gas companies, and other energy service companies to develop Energy Efficiency Plans to meet goals set forth by the Ministry and the Mining and Energy Planning Unit.

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

Current GHG emissions legislation has not resulted in material compliance costs; however, it is not possible at this time to predict whether proposed legislation or regulations will be adopted, and any such future laws and regulations could result in additional compliance costs or additional operating restrictions. If we are unable to recover a significant amount of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Significant restrictions on GHG emissions could result in decreased demand for the oil that we produce, with a resulting decrease in the value of our reserves. Further, to the extent financial markets view climate change and GHG emissions as a financial risk; this could negatively impact our cost of or access to capital. Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company's causation of or contribution to the asserted damage, or to other mitigating factors. Finally, although we strive to operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

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

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

Shares of our Common Stock are listed on the NYSE American, the TSX and the London Stock Exchange ("LSE") and investors seeking to take advantage of price differences between such markets may create unexpected volatility in market prices

Shares of our Common Stock are listed on the NYSE American, the TSX and the LSE. While the Common Stock is traded on such markets, the price and volume levels could fluctuate significantly on any market independently of the price or trading volume on other markets. Investors could seek to sell or purchase shares of Common Stock to take advantage of any price differences between the NYSE American, the TSX and the LSE through a practice referred to as arbitrage. Any arbitrage activity could create unexpected volatility in the price of the Common Stock on any of these exchanges or the volume of Common Stock available for trading on any of these markets. In addition, shareholders in any of these jurisdictions will not be able to transfer such shares of

Common Stock for trading on another market without effecting necessary procedures with our transfer agent or registrar. This could result in time delays and additional cost for shareholders of the Common Stock.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

The ANH and Gran Tierra are engaged in discussions regarding the interpretation of whether certain transportation and related costs are eligible to be deducted in the calculation of the HPR royalty. Discussions with the ANH are ongoing. Based on our understanding of the ANH's position, the estimated compensation, which would be payable if the ANH’s interpretation is correct, could be up to $56.3 million as at December 31, 2018. At this time, no amount has been accrued in the financial statements as Gran Tierra does not consider it probable that a loss will be incurred.

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

Item 4. Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

Set forth below is information regarding our executive officers as of February 22, 2019.



Name	Age	Position
Gary S. Guidry	63	President and Chief Executive Officer, Director
Ryan Ellson	43	Chief Financial Officer
Ed Caldwell	69	Vice President, Health, Safety and Environment & Corporate Social Responsibility
James Evans	53	Vice President, Corporate Services
Alan Johnson	47	Vice President, Asset Management
Glen Mah	62	Vice President, Business Development
Susan Mawdsley	52	Vice President, Finance and Corporate Controller
Rodger Trimble	57	Vice President, Investor Relations
Lawrence West	62	Vice President, Exploration

•

Gary Guidry, Chief Executive Officer and President. Mr. Guidry has been Gran Tierra's Chief Executive Officer and President since May 7, 2015. Mr. Guidry was the Chief Executive Officer of Onza Energy Inc. from January 2014, until May 2015. From July 2011 to July 2014, Mr. Guidry served as President and Chief Executive Officer of Caracal Energy Inc. Mr. Guidry also served as President and CEO of Orion Oil & Gas Corp. from October 2009 to July 2011, Tanganyika Oil Corp. from May 2005 to January 2009, and Calpine Natural Gas Trust from October 2003 to February 2005. As chief executive officer of these companies, Mr. Guidry was responsible for overseeing all aspects of the respective company’s business. Mr. Guidry currently sits on the board of Africa Oil Corp. (since April 2008) where he also serves as a member of the Audit Committee and the board of PetroTal Corp. (since December 2017). From September 2010 to October 2011, Mr. Guidry served on the board of Zodiac Exploration Corp., from October 2009 to March 2014, he served on the board of TransGlobe Energy Corp., and from February 2007 to May 2018, he served on the board of Shamaran Petroleum Corp. Prior to these positions, Mr. Guidry served as Senior Vice President and subsequently President of Alberta Energy Company International, and President and General Manager of Canadian Occidental Petroleum’s Nigerian operations. Mr. Guidry has directed exploration and production operations in Yemen, Syria and Egypt and has worked for oil and gas companies around the world in the U.S., Colombia, Ecuador, Venezuela, Argentina and Oman. Mr. Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University.

•

Ryan Ellson, Chief Financial Officer. Mr. Ellson has been Gran Tierra's Chief Financial Officer since May 2015. Mr. Ellson has 17 years of experience in a broad range of international corporate finance and accounting roles. Mr. Ellson is currently a Director of PetroTal Corp. (since December 2017). Mr. Ellson was CFO of Onza Energy Inc. from January 2015 to May 2015. From July 2014 until December 2014 Mr. Ellson was Head of Finance for Glencore E&P (Canada) Inc. and prior thereto Vice President, Finance at Caracal Energy Inc., a London Stock Exchange ("LSE") listed company with operations in Chad, Africa from August 2011 until July 2014. Prior to Caracal, Mr. Ellson was Vice President of Finance at Sea Dragon Energy from April 2010 until August 2011. In these positions, Mr. Ellson oversaw financial and accounting functions, implemented and oversaw internal financial controls, secured a reserve based lending facility and was involved in multiple capital raises. Mr. Ellson has held management and executive positions with companies operating in Chad, Egypt, India and Canada. Mr. Ellson is a Chartered Professional Accountant and holds a Bachelor of Commerce and a Master of Professional Accounting from the University of Saskatchewan.

•

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

•

James Evans, Vice President, Corporate Services. Mr. Evans has been Gran Tierra's Vice President, Corporate Services, since May 2015. Mr. Evans has over 25 years of experience including working the last 13 years in the international oil and gas industry. Most recently, Mr. Evans was the Head of Compliance & Corporate Services for Glencore E&P (Canada) Inc. from July 2014 to December 2014, and prior thereto Vice President of Compliance & Corporate Services at Caracal Energy Inc. from July 2011 to June 2014 where he oversaw the execution of corporate strategy and goals, developed and implemented a robust corporate compliance program, and managed all aspects of IT, document control, security and administration. Mr. Evans also managed the recruitment, training and retention of staff in both Calgary and Chad. He oversaw the growth of Caracal Energy from seven employees to more than 400 at the time of sale to Glencore. Prior to Caracal, Mr. Evans held senior management and executive positions at Orion Oil and Gas and Tanganyika Oil, with operating experience in Egypt, Syria and Canada. Mr. Evans is a Certified General Accountant and holds a Bachelor of Commerce degree from the University of Calgary.

•

Alan Johnson, Vice President, Asset Management. Mr. Johnson has been Gran Tierra's Vice President, Asset Management, since May 2015. Mr. Johnson is a professional engineer with more than 25 years of experience working internationally in the oil and gas industry. His experience includes varied technical, managerial and executive roles in drilling, production, reservoir, reserves, corporate planning and asset management. Most recently Mr. Johnson was Head of Asset Management for Glencore E&P (Canada) Inc. from April 2014 to April 2015, where he was responsible for all development activities in Chad and prior thereto Director of Asset Management at Caracal Energy from August 2011 to March 2014, where he was responsible for development activities in the Doba basin in Chad, Africa. Mr. Johnson was instrumental in developing oil and gas assets in remote areas of southern Chad, achieving first production in less than 18 months. Mr. Johnson started his E&P career with Shell International in the Dutch North Sea. He then held positions of increasing responsibility with Shell Canada, APF Energy, Rockyview Energy, Delphi Energy and BG Australia. Mr. Johnson graduated with a 1st Class B. Eng (Hons) from Heriot Watt University in Scotland. Mr. Johnson is a Chartered Engineer in the UK and a Professional Engineer in Alberta.

•

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

•

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

and gas companies. Ms. Mawdsley is a Chartered Professional Accountant and holds a Bachelor of Music in Performance degree from the University of Toronto.

•

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

•

Lawrence West. Vice President, Exploration. Mr. West has been Gran Tierra's Vice President, Exploration, since May 2015. Mr. West has over 35 years of experience as an executive, explorationist, and geologist. Most recently, Mr. West was Vice President, Exploration at Caracal Energy from July 2011 to June 2014. Mr. West built a multi-disciplinary team to assess resources and grow reserves in the interior rift basins within Chad and led a successful exploration program. During his tenure he successfully executed two large 2D/3D seismic shoots in remote frontier basins, on time and on budget. Prior to Caracal he has been involved in starting and growing several public and private companies, including Reserve Royalty Corp., Chariot Energy, Auriga Energy and Orion Oil and Gas. Lawrence worked at Alberta Energy Company (AEC), where he was on the team that merged with Conwest. He built and led the AEC East team to the Rocky Mountain USA basins. His career began with Imperial Oil working on prospect and reservoir characterization, in multi-disciplinary teams, and as a technical mentor to exploration teams. Lawrence has an Honours Bachelor of Science in Geology from McMaster University and an MBA, specializing in economics, from the University of Calgary.

PART II

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

Shares of our Common Stock trade on the NYSE American, the Toronto Stock Exchange (“TSX”) and on the London Stock Exchange (“LSE”) under the symbol “GTE”.

As of February 22, 2019, there were approximately 33 holders of record of shares of our Common Stock and 387,079,027 shares outstanding with $0.001 par value.

Dividend Policy

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

Issuer Purchases of Equity Securities



	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share⁽²⁾	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs⁽³⁾
October 1-31, 2018	—	—	—	18,765,120
November 1-30, 2018	2,921,776	2.79	2,921,776	15,843,344
December 1-31, 2018	1,346,481	2.56	1,346,481	14,496,863
	4,268,257	2.68	4,268,257	14,496,863

⁽¹⁾ Based on settlement date.

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

⁽³⁾ On March 7, 2018, we announced that we intended to implement a share repurchase program (the “2018 Program”) through the facilities of the TSX and eligible alternative trading platforms in Canada. We received regulatory approval from the TSX to commence the 2018 Program on March 12, 2018. We are able to purchase at prevailing market prices up to 19,269,732 shares of Common Stock, representing approximately 5% of our issued and outstanding shares of Common Stock as of March 8, 2018.

Shares purchased pursuant to the 2018 Program to date have been canceled. The 2018 Program will expire on March 11, 2019, or earlier if the 5% share maximum is reached. The 2018 Program could be terminated by us at any time, subject to compliance with regulatory requirements. As such, there can be no assurance regarding the total number of shares that may be repurchased under the 2018 Program.

Performance Graph

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

The performance graph below shows the cumulative total shareholder return on our shares for the period starting on December 31, 2013, and ending on December 31, 2018, which was the end of fiscal 2018. This is compared with the cumulative total returns over the same period of the S&P 500 Total Return Index and the S&P O&G E&P Select Index Total Return. The graph assumes that, on December 31, 2013, $100 was invested in our shares and $100 was invested in each of the other two indices, with dividends reinvested on the ex-dividend date without payment of any commissions. The performance shown in the graph represents past performance and should not be considered an indication of future performance.

Item 6. Selected Financial Data

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



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

Expenses
Operating	111,272		87,855		64,173	60,756		74,459
Workover	34,437		22,014		22,752	14,809		15,294
Transportation	28,993		25,107		31,776	40,204		24,196



Depletion, depreciation and accretion	197,867		131,335			139,535			176,386			185,877
Asset impairment	—		1,514			616,649			323,918			265,126
G&A	39,483		39,014			33,218			32,353			51,249
Severance	2,361		1,287			1,319			8,990			—
Transaction	—		—			7,325			—			—
Equity tax	—		1,224			3,098			3,769			—
Foreign exchange loss (gain)	9,957		2,067			(1,469		)	(17,242		)	(39,535		)
Financial instruments loss	12,296		15,929			10,279			2,027			4,722
Other gain	—		—			—			(502		)	(2,000		)
Interest expense	27,364		13,882			14,145			—			—
	464,030		341,228			942,800			645,468			579,388

(Loss) on sale and gain on acquisition	—		(44,385		)	929			—			—
Interest income	2,086		1,209			2,368			1,369			2,856
Income (loss) from continuing operations before income taxes	151,487		37,330			(650,234		)	(368,088		)	(17,134		)

Current income tax expense	43,903		24,322			20,122			15,383			92,865
Deferred income tax expense (recovery)	4,968		44,716			(204,791		)	(115,442		)	34,350
	48,871		69,038			(184,669		)	(100,059		)	127,215

Income (loss) from continuing operations	102,616		(31,708		)	(465,565		)	(268,029		)	(144,349		)
Loss from discontinued operations, net of income taxes	—		—			—			—			(26,990		)
Net income (loss)	$	102,616	$	(31,708	)	(465,565		)	$	(268,029	)	$	(171,339	)

Income (Loss) per Share
Basic
Income (loss) from continuing operations	$	0.26	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.51	)
Loss from discontinued operations, net of income taxes	—		—			—			—			(0.09		)
Net income (loss)	$	0.26	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.60	)

Diluted
Income (loss) from continuing operations	$	0.26	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.51	)
Loss from discontinued operations, net of income taxes	—		—			—			—			(0.09		)
Net income (loss)	$	0.26	$	(0.08	)	$	(1.45	)	$	(0.94	)	$	(0.60	)
Balance Sheet Data
	As at December 31,
	2018		2017			2016			2015			2014
Cash and cash equivalents	$	51,040	$	12,326		$	25,175		$	145,342		$	331,848
Working capital (deficiency)	33,145		(11,724		)	(23,344		)	160,449			239,312
Oil and gas properties	1,310,026		1,094,029			1,060,093			780,360			1,117,931



Deferred tax asset - long-term	45,437	57,310	1,611	3,241	2,153
Total assets	1,676,584	1,429,619	1,367,896	1,146,118	1,714,050
Long-term debt	399,415	256,542	197,083	—	—
Deferred tax liability - long-term	23,419	28,417	107,230	34,592	176,364
Total long-term liabilities	477,454	336,315	353,880	70,485	213,039
Shareholders’ equity	1,029,750	936,335	858,987	1,001,642	1,276,685

During the year ended December 31, 2018, we completed acquisitions in Colombia for an aggregate of $53.2 million. An aggregate of $347.1 million in capital expenditures were incurred for a year, which resulted in a total of 28 wells drilled.

On December 18, 2017, we completed the sale of our Peru business unit. Pursuant to the divestiture, PetroTal acquired all of the issued and outstanding shares of our indirect, wholly owned subsidiary that indirectly held all of our Peruvian assets for aggregate consideration of $33.5 million, comprised of approximately 187.3 million common shares of PetroTal 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 and subsequently exchanged them for approximately 58.9 million common shares of Sterling. After giving effect to the divestiture, we directly and indirectly hold approximately 246.2 million common shares representing approximately 46% of Sterling's issued and outstanding common shares.

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

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

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

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

Overview

We are a company focused on oil and gas exploration and production in Colombia. Our Colombian properties represented 100% of our proved reserves NAR at December 31, 2018. For the year ended December 31, 2018, 100% of our revenue and other income was generated in Colombia (year ended December 31, 2017- 98%; year ended December 31, 2016 - 97%). We are headquartered in Calgary, Alberta, Canada.

As of December 31, 2018, we had estimated proved reserves NAR of 54.3 MMBOE, of which 68% were proved developed reserves and 99% were oil.

As discussed under Items 1 and 2. “Business and Properties,” in 2018, we completed certain asset acquisitions to further enhance our strategy.

Financial and Operational Highlights

Key Highlights


•	Net income in 2018 was $102.6 million, or $0.26 per share basic and diluted compared to net loss of $31.7 million, or $(0.08) per share basic and diluted in 2017.


•	EBITDA⁽¹⁾ more than doubled 106% to $376.7 million in 2018 compared with $182.5 million in 2017. Net debt⁽¹⁾ to EBITDA was 1.0 times at December 31, 2018.


•	Funds flow from operations⁽¹⁾ for 2018 increased by 39% to $306.4 million compared with $220.2 million in 2017.


•	Oil and gas sales for 2018 increased 45% to $613.4 million compared with $421.7 million in 2017.


•	Achieved a new Company milestone with record high average production before royalties in 2018 of 36,209 BOEPD, 15% higher compared to 31,426 BOEPD⁽²⁾in 2017 and 38% higher than 26,216 in 2016.


•	Total Company's 2018 average production NAR was 29,053 BOEPD, 8% higher compared with 2017.


•	Total Company's 2018 oil and gas sales volumes increased by 8% to 28,717 BOEPD compared with 2017.


•	Oil and gas sales per BOE for 2018 were $58.53, 35% higher compared with 2017.


•	Operating netback⁽¹⁾ per BOE for 2018 was $41.85 per BOE, 42% higher compared with 2017.


•	Operating expenses per BOE for 2018 were $10.62 per BOE, 18% higher compared with 2017 primarily as a result of higher power generation and equipment rental costs required to manage the capacity limitations in Acordionero field as a result of rapid production growth


•	Workover expenses per BOE for 2018 increased by 46% to $3.29 compared with 2017 primarily as a result of pump failures due to unreliable power.


•	Quality and transportation discount per BOE for 2018 was $13.16.


•	Transportation expenses per BOE for 2018 increased by 7% to $2.77 compared with 2017, due to a lower percentage of volumes being sold at the wellhead where transportation is netted against sales price.


•	General and administrative ("G&A") expenses before stock-based compensation per BOE for 2018 decreased by 2% to $2.99 per BOE compared to 2017.



(Thousands of U.S. Dollars, unless otherwise noted)	Year Ended December 31,
SEC Compliant Reserves, NAR (MMBOE)	2018			% Change		2017			% Change		2016
Estimated Proved Oil and Gas Reserves	54			(8	)	59			11		53

Estimated Probable Oil and Gas Reserves	62			13		55			25		44

Estimated Possible Oil and Gas Reserves	49			(16	)	58			(9	)	64

Average Consolidated Daily Volumes (BOEPD)
Working Interest Production Before Royalties	36,209			13		32,105			19		27,062
Royalties	(7,156		)	35		(5,320		)	37		(3,875		)
Production NAR	29,053			8		26,785			16		23,187
(Increase) Decrease in Inventory	(336		)	250		(96		)	(113	)	767
Sales⁽³⁾	28,717			8		26,689			11		23,954

Net Income (Loss)	$	102,616		424		$	(31,708	)	93		$	(465,565	)

Operating Netback
Oil and Natural Gas Sales	$	613,431		45		$	421,734		46		$	289,269
Operating Expenses	(111,272		)	27		(87,855		)	37		(64,173		)
Workover Expenses	(34,437		)	56		(22,014		)	(3	)	(22,752		)
Transportation Expenses	(28,993		)	15		(25,107		)	(21	)	(31,776		)
Operating Netback⁽¹⁾	$	438,729		53		$	286,758		68		$	170,568

G&A Expenses Before Stock-Based Compensation	$	31,369		5		$	29,775		10		$	27,127

G&A Stock-Based Compensation	$	8,114		(12	)	$	9,239		52		$	6,091

EBITDA⁽¹⁾	$	376,718		106		$	182,547		(137	)	$	(496,554	)

Funds Flow From Operations⁽¹⁾	$	306,449		39		$	220,197		110		$	104,984

Capital Expenditures	$	347,093		38		$	251,041		96		$	127,789

Net Cash Received on Dispositions	$	—		(100	)	$	32,968		—		$	—

Cash Paid for Acquisitions, Net of Cash Acquired	$	53,200		55		$	34,410		(93	)	$	507,584



	As at December 31,
(Thousands of U.S. Dollars)	2018		% Change		2017		% Change		2016
Cash, Cash Equivalents and Current Restricted Cash and Cash Equivalents	$	52,309	117		$	24,113	(28	)	$	33,497

Revolving Credit Facility	$	—	(100	)	$	148,000	64		$	90,000

Senior Notes	$	300,000	100		$	—	—		$	—

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

⁽¹⁾Non-GAAP measures

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

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

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



	Year Ended December 31,
(Thousands of U.S. Dollars)	2018		2017			2016
Net Income (loss)	$	102,616	$	(31,708	)	$	(465,565	)
Adjustments to reconcile net loss to adjusted EBITDA
DD&A expenses	197,867		131,335			139,535
Interest expense	27,364		13,882			14,145
Income tax expense (recovery)	48,871		69,038			(184,669		)
EBITDA (non-GAAP)	$	376,718	$	182,547		$	(496,554	)

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



	Year Ended December 31,
(Thousands of U.S. Dollars)	2018			2017			2016
Net Income (loss)	$	102,616		$	(31,708	)	$	(465,565	)
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses	197,867			131,335			139,535
Asset impairment	—			1,514			616,649
Deferred tax expense (recovery)	4,968			44,716			(204,791		)
Stock-based compensation expense	8,299			9,775			6,339
Amortization of debt issuance costs	3,183			2,415			5,691
Cash settlement of RSUs	(360		)	(564		)	(1,234		)
Unrealized foreign exchange loss (gain)	11,511			837			(1,428		)
Financial instruments loss	12,296			15,929			10,279
Cash settlement of financial instruments	(33,931		)	1,563			438
Loss on sale and (gain) on acquisition	—			44,385			(929		)
Funds flow from operations (non-GAAP)	$	306,449		$	220,197		$	104,984

Net debt at year-end 2018 of $366 million comprised of working capital surplus of $33 million, convertible notes of $112 million (net of unamortized fees; $115 million gross) and high yield bond of $289 million (net of unamortized fees; $300 million gross), unamortized reserves-based credit facility fees of $2 million (net of unamortized fees; $0 million gross).

⁽²⁾Excluding 2017 and 2016 average WI production of 679 and 846 BOEPD respectively, relating to the Brazil operations, which were sold in June 2017.

⁽³⁾ Sales volumes represent production NAR adjusted for inventory changes. In 2017 and 2016, Brazil contributed 580 BOEPD and 713 BOEPD, respectively.

Consolidated Results of Operations



	Year Ended December 31,
	2018		% Change		2017			% Change		2016
(Thousands of U.S. Dollars)
Oil and natural gas sales	$	613,431	45		$	421,734		46		$	289,269
Operating expenses	111,272		27		87,855			37		64,173
Workover expenses	34,437		56		22,014			(3	)	22,752
Transportation expenses	28,993		15		25,107			(21	)	31,776
Operating netback⁽¹⁾	438,729		53		286,758			68		170,568

DD&A expenses	197,867		51		131,335			(6	)	139,535
Asset impairment	—		(100	)	1,514			(100	)	616,649
G&A expenses before stock-based compensation	31,369		5		29,775			10		27,127
G&A stock-based compensation expense	8,114		(12	)	9,239			52		6,091
Severance expenses	2,361		83		1,287			(2	)	1,319
Transaction expenses	—		—		—			(100	)	7,325
Equity tax	—		(100	)	1,224			(60	)	3,098
Foreign exchange loss (gain)	9,957		382		2,067			241		(1,469		)
Financial instruments loss	12,296		(23	)	15,929			55		10,279
Interest expense	27,364		97		13,882			(2	)	14,145
	289,328		40		206,252			(75	)	824,099

(Loss) on sale and gain on acquisition	—		—		(44,385		)	—		929
Interest income	2,086		73		1,209			(49	)	2,368

Income (loss) before income taxes	151,487		306		37,330			106		(650,234		)

Current income tax expense	43,903		81		24,322			21		20,122
Deferred income tax expense (recovery)	4,968		(89	)	44,716			122		(204,791		)
	48,871		(29	)	69,038			137		(184,669		)

Net Income (loss)	$	102,616	424		$	(31,708	)	93		$	(465,565	)

Sales Volumes (NAR)
Total sales volumes, BOEPD	28,717		8		26,689			11		23,954

Brent Price per bbl	$	71.69	31		$	54.82		24		$	44.33

Consolidated Results of Operations per BOE Sales Volumes (NAR)
Oil and natural gas sales	$	58.53	35		$	43.29		31		$	33.00
Operating expenses	10.62		18		9.02			23		7.32
Workover expenses	3.29		46		2.26			(13	)	2.60
Transportation expenses	2.77		7		2.58			(29	)	3.62
Operating netback⁽¹⁾	41.85		42		29.43			51		19.46



DD&A expenses	18.88	40		13.48	(15	)	15.92
Asset impairment	—	(100	)	0.16	(100	)	70.34
G&A expenses before stock-based compensation	2.99	(2	)	3.06	(1	)	3.10
G&A stock-based compensation expense	0.77	(19	)	0.95	38		0.69
Severance expenses	0.23	77		0.13	(13	)	0.15
Transaction expenses	—	—		—	(100	)	0.84
Equity tax	—	(100	)	0.13	(63	)	0.35
Foreign exchange loss (gain)	0.95	352		0.21	224		(0.17)
Financial instruments loss	1.17	(29	)	1.64	40		1.17
Interest expense	2.61	83