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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)

 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2020

or
 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)
 
Delaware98-0479924
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
900, 520 - 3 Avenue SW
Calgary,AlbertaCanadaT2P 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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock, par value $0.001 per share
GTE
NYSE American
Toronto Stock Exchange
London Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☐ No
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 ☐ No
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 ☒ No ☐

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  ☒ No ☐

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 filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company

 
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.                                                       ☐    

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.                 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).      Yes No ☒
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $96.8 million.

On February 19, 2021, 366,981,556 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 2021 annual meeting of stockholders, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after December 31, 2020.


1


Gran Tierra Energy Inc.

Annual Report on Form 10-K

Year Ended December 31, 2020

Table of Contents
 
  Page
PART I  
Items 1 and 2.Business and Properties
Item 1A.Risk Factors
Item 1B.Unresolved Staff Comments
Item 3.Legal Proceedings
Item 4.Mine Safety Disclosures
PART II
Item 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 8.Financial Statements and Supplementary Data
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.Controls and Procedures
Item 9B.Other Information
  
PART III 
Item 10.Directors, Executive Officers and Corporate Governance
Item 11.Executive Compensation
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.Certain Relationships and Related Transactions, and Director Independence
Item 14.Principal Accounting Fees and Services
PART IV
Item 15.Exhibits, Financial Statement Schedules
Item 16.Form 10-K Summary
SIGNATURES

2


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 benefits of the changes in our capital program or expenditures, our liquidity and financial condition, the impacts of the novel coronavirus (COVID-19) pandemic 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, our ability to comply with covenants in our credit
agreement and indentures and make borrowings under our credit agreement; a reduction in our borrowing base and our ability to repay any excess borrowings; sustained or future declines in commodity prices and the demand for oil; continued or future excess supply of oil and natural gas; potential future impairments and reductions in proved reserve quantities and value; continued spread of the COVID-19 virus and extensions of previously announced lockdowns and possible future restrictions against oil and gas activity in Colombia and Ecuador; our operations are located in South America, and unexpected problems can arise due to guerilla activity and other local conditions; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to raise capital; our ability to identify and complete successful acquisitions; our ability to execute business plans; unexpected delays and difficulties in developing currently owned properties may occur; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; current global economic and credit market conditions may impact oil prices and oil consumption differently than we currently predict, which could cause us to further modify our strategy and capital spending program; volatility or declines in the trading price of our common stock and the continued listing of our shares on a national stock exchange; and those factors set out in Part I, Item 1A “Risk Factors” in this Annual Report on Form 10-K. The unprecedented nature of the current pandemic and downturn in the worldwide economy and oil and gas industry makes, including the unpredictable nature of the resurgence of cases and governmental responses, make it more difficult to predict the accuracy of the forward-looking statements. 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 obligation or undertaking to publicly release any updates or revisions to, or to withdraw, 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:

bblbarrelMcfthousand cubic feet
Mbblthousand barrelsMMcfmillion cubic feet
MMbblmillion barrelsBcfbillion cubic feet
BOEbarrels of oil equivalentbopdbarrels of oil per day
MMBOEmillion barrels of oil equivalentNARnet after royalty
BOEPDbarrels of oil equivalent per dayBOPDbarrels of oil per day

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”. 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.

3


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.
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(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 international oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 100% of our proved reserves NAR at December 31, 2020. For the year ended December 31, 2020, 100% (2019 - 100%) 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.

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

2020 Operational Highlights

During the year ended December 31, 2020, we incurred capital expenditures of $96.3 million, the majority of which were incurred in Colombia. In 2020, we drilled 7 development wells and one water injector, all of which were drilled in the Midas Block. As at December 31, 2020, 6 of the development wells were producing and one was in progress.

Of the three wells in progress in Colombia as at December 31, 2019, one was inactive pending future tests and two were dry at December 31, 2020.

The COVID-19 pandemic and resulting economic slowdown disrupted the overall global supply and demand for crude oil for the year ended December 31, 2020. Governments worldwide, including those in Canada, Colombia and Ecuador, the countries where we currently operate, enacted emergency measures to combat the spread of the virus, including the implementation of travel bans and self-imposed quarantines, which decreased the demand for and increased the supply of oil. On April 12, 2020,
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certain members of OPEC+ had agreed to production cuts intended to mitigate the oil supply and demand imbalance to stabilize prices. On December 3, 2020, certain members agreed to modestly increase production in January 2021; however, members eventually agreed to keep production levels mostly steady in February and March 2021 as certain economies have been forced to lockdown again due to a resurgence of the pandemic and the difficulties that governments have experienced in distributing vaccines. Though declining U.S. production has helped to mitigate the supply and demand imbalance experienced during 2020, we expect that oil supply and demand in the near term will continue to be influenced by the duration and severity of the COVID-19 pandemic and its resulting impact on global economies and the extent to which countries abide by the OPEC+ production agreement.

2021 Outlook

Our Colombian operation, which represents 100% of our production, is expected to represent 98% of our 2021 capital budget with the remainder allocated to exploration activities in Ecuador.

The table below shows the break-down of our 2021 capital program:

Number of Wells
(Gross)
Number of Wells
(Net)
2021 Capital Budget
($ million)
Colombia
Development
14-18
14-18
118-138
Exploration— — 
9
Ecuador
Exploration— — 
3
14-18
14-18
130-150

Our base capital program for 2021 is $130 million to $150 million for exploration and development based on a mid-point range for budgeted exploration costs. Based on the mid-point of the 2021 guidance, the capital budget is forecasted to be approximately 91% directed to development and 9% to exploration activities. Approximately 21% of the development activities included in the 2021 capital program are expected to be directed to facilities.

We expect our 2021 capital program to be fully funded by cash flows from operations. Funding this program from cash flow from operations relies in part on Brent oil prices being at least $49 per bbl for 2021.

Business Strategy

We are an international exploration and production company focused on hydrocarbon development in proven, under-explored conventional basins which have access to established infrastructure and competitive fiscal regimes. Our mandate is to develop high value resource opportunities in order to deliver top-quartile returns. We intend to continue to high-grade our portfolio, with a continued focus on operational excellence, safety, and stakeholder returns. The senior management team has a proven track record in developing technically difficult reservoirs, enhanced oil recovery and operating in remote locations in demanding jurisdictions. We aim to have meaningful and sustainable impact through social investments within the communities we operate. Our "Beyond Compliance Policy" focuses on our commitments to environmental, social and governance excellence.

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Oil and Gas Properties - Colombia and Ecuador
gte-20201231_g1.jpg

As of December 31, 2020, excluding blocks subject to relinquishment, we had interests in 27 blocks in Colombia, 3 blocks in Ecuador and were the operator on 28 of those blocks.


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Exploration Blocks & Commitments

The following table provides a summary of our exploration commitments for certain blocks as of December 31, 2020:

BasinBlockCurrent PhaseRemaining Commitments, Current Phase
Colombia
PutumayoAlea
1848-A
3 & 4one exploration well
PutumayoAlea
1947-C
2one exploration well
PutumayoPUT-12*two exploration wells
PutumayoPUT-22*three exploration wells
PutumayoPUT-41one exploration well
PutumayoPUT-72two exploration wells
PutumayoPUT-101*73 km 2D seismic, two exploration wells
PutumayoPUT-251one exploration well
PutumayoPUT-311202 km 2D seismic, one exploration well
LlanosLLA-11*
97.5 km2 3D seismic, one exploration well
LlanosLLA-51*
133 km2 3D seismic, one exploration well
LlanosLLA-221 & 2*
85 km2 3D seismic, one exploration well
LlanosLLA-701*
163 km2 3D seismic, one exploration well
LlanosLLA-851
50 km2 3D seismic, 451 km2 3D seismic reprocessing
MMVVMM-241
50 km2 3D seismic, 100 km 2D seismic reprocessing, 100 km aerogeophysics, 100 km2 remote sensing, 80 km2 surface geochemistry, one exploration well
Ecuador
OrienteCharapa150 km 2D seismic, seven exploration wells
OrienteChanangue1five exploration wells
OrienteIguana1two exploration wells
*As of December 31, 2020, exploration has been suspended due to licensing restrictions, security issues or social reasons

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, increasing in a linear fashion from 8% to 20% for gross production between 5,000 and 125,000 bopd and is fixed at 20% for gross production between 125,000 and 400,000 bopd. For gross production
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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 the sliding scale for new discoveries or incremental production duly approved by ANH. In addition to the sliding scale royalty, there are additional x-factor royalties of 1% for Llanos-22, Putumayo-2, Putumayo-4, Putumayo-7, Putumayo-21 and VMM-24; 2% for Llanos-85, 3% 5% for Putumayo-1; 12% for Putumayo-31; 19% for Putumayo 25; 31% for Llanos-1 and Llanos -70.

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 16% for gross production between 28.5 MMcf of gas per day and 712.5 MMcf of gas per day and is stable at 16% for gross production between 712.5 to 2,280 MMcf of gas per day, and then increases in a linear fashion from 16% to 20% for gross production between 2.28 to 3.42 Bcf of gas per day. For gross production in excess of 3.42 Bcf of gas per day the royalty rate is fixed at 20%.

An additional high price share royalty ("HPR") is applicable to exploration and production contracts signed under new ANH oil regulatory regime in 2004 and onwards when cumulative gross production (net of royalty) from an Exploitation Area is greater than 5 MMbbls of oil and WTI reference price exceeds the trigger price defined in the contract. The HPR is calculated using the associated production multiplied by Q factor which is calculated as follows:

Q factor = (WTI price - Base Price(1))/WTI Price * 30%

Quality (Oil API)
(1)Base Price ($/bbl)
< 10 o
Nil
10o to 15o
57.20
15o to 22o
40.04
22o to 29o
38.61
> 29o
37.16

At December 31, 2020, HPR was applicable to our production from the Costayaco and Moqueta Exploitation Areas in the Chaza Block and the Acordionero Exploitation Area in the Midas Block.

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. 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. 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 value added tax ("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.

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Administrative Facilities

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

Estimated Reserves

Our 2020 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 Bachelor of Geological Engineering, graduating with Great Distinction, and a Masters of Chemical Engineering (petroleum). He is responsible for our engineering activities including reserves reporting, asset evaluation, reservoir management and field development. He has over 30 years of experience in the oil and gas industry with extensive experience in reservoir management, production and operations.

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 Company to ensure consistent and appropriate standards and procedures. Our policies are applied by all staff involved in generating and reporting reserve estimates including geological, engineering and finance personnel.

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

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Estimates of proved reserves are generated through the integration of relevant geological, engineering, and production data, utilizing technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us. The probable reserves that have been assigned as of December 31, 2020 were based on both the greater percentage of recovery of the hydrocarbons in place than assumed for proved reserves, as well as to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain.

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Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of possible reserves are also inherently imprecise. Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. The possible reserves that have been assigned as of December 31, 2020 were based on both the greater percentage of recovery of the hydrocarbons in place than assumed for probable reserves as well as to areas of a reservoir adjacent to probable reserves where data control or interpretations of available data are less certain.

The following table sets forth our estimated reserves NAR as of December 31, 2020:

OilNatural GasOil and Natural Gas
Reserves Category(Mbbl)(MMcf)(MBOE)
Proved
Total proved developed reserves38,660 633 38,766 
Total proved undeveloped reserves26,032 1,022 26,202 
Total proved reserves64,692 1,655 64,968 
Probable (1)
Total probable developed reserves16,818 96 16,834 
Total probable undeveloped reserves26,997 1,044 27,171 
Total probable reserves43,815 1,140 44,005 
Possible (1)
Total possible developed reserves14,145 205 14,179 
Total possible undeveloped reserves29,171 1,206 29,372 
Total possible reserves43,316 1,411 43,551 

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

Product Prices Used In Reserves Estimates

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

Oil ($/bbl) - Colombia$35.33 
Natural Gas ($/Mcf) - Colombia$3.67 
ICE Brent - average of the first day of each month price for the 12-month period$43.43 

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, 2020, we had total proved undeveloped reserves NAR of 26.2 MMBOE (December 31, 2019 - 31.0 MMBOE), which were 100% in Colombia (December 31, 2019 – 100% in Colombia). Approximately 51%, 12%, 14% and 15% for a total of 92% of proved undeveloped reserves are located in our Acordionero, Cohembi, Costayaco and Moqueta Fields, respectively, in Colombia. None of our proved undeveloped reserves at December 31, 2020 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.

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Changes in proved undeveloped reserves during the year ended December 31, 2020 are shown in the table below:
Colombia - Oil Equivalent
(MMBOE)
Balance, December 31, 2019
$31.0 
Converted to proved producing$(4.9)
Technical and economic revisions$(1.8)
Extensions$0.9 
Improved recovery$1.0 
Balance, December 31, 2020
$26.2 

Changes in proved undeveloped reserves during the year ended December 31, 2020 shown in the table above primarily resulted from the following significant factors:

Converted to Proved Producing. In 2020, we converted 4.9 MMBOE, or 16% of 2019 proved undeveloped reserves to developed status. In 2020, we made investments consisting solely of capital expenditures of $19.3 million in Colombia associated with drilling 8 wells in the Midas Block.

Technical and Economic Revisions. During the year ended December 31, 2020, we experienced revisions of 1.8 MMBOE of proved undeveloped reserves primarily as a result of an increase in uneconomic reserves due to lower pricing.

Extensions. We added 0.9 MMBOE to proved undeveloped reserves during the year ended December 31, 2020, which were attributed to extensions of 0.4 MMBOE in the Acordionero field and 0.5 MMBOE in the Costayaco field.

Improved Recoveries. We added 1.0 MMBOE to proved undeveloped reserves during the year ended December 31, 2020, which were attributed to better recoveries of heavy oil in the Acordionero field.

Production, Revenue and Price History

Certain information concerning production, prices, revenues and operating expenses for the years ended December 31, 2020 and 2019 is set forth in Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” and in the “Supplementary Data (Unaudited)” provided following our Financial Statements in Item 8, which information is incorporated by reference here.

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The following table presents NAR oil production, average sales prices and operating expenses per NAR oil production from our major Fields Costayaco, Moqueta, Cohembi and Acordionero and from all of our properties for each of the three years ended December 31, 2020:

Costayaco (1)
Moqueta (1)
Cohembi (1)
Acordionero (1)
Total for all
  properties (2)
Year Ended December 31, 2020
Oil production NAR bbl 1,773,723792,011438,7993,612,3387,346,200
Average sales price of oil per bbl$32.07 $31.52 $32.32 $32.45 $32.38 
Operating expenses of oil per bbl (3)
$17.63 $17.71 $15.60 $12.19 $16.67 
Year Ended December 31, 2019
Oil production NAR bbl 1,966,585 1,022,391 675,086 5,166,430 10,590,137 
Average sales price of oil per bbl$56.38 $55.93 $54.35 $54.17 $53.92 
Operating expenses of oil per bbl (3)
$18.95 $18.88 $23.94 $14.60 $19.23 
Year Ended December 31, 2018
Oil production NAR bbl 2,244,497 1,020,673 324,798 5,469,072 10,604,197 
Average sales price of oil per bbl$58.19 $59.87 $55.06 $57.64 $57.85 
Operating expenses of oil per bbl (3)
$22.23 $20.47 $22.81 $11.22 $16.47 

(1) 100% of product sales were oil
(2) Includes de minimis natural gas production from non-core properties from Colombia of 214,719 Mcf (35,787 boe), 361,065 Mcf
(60,178 boe) and 208,961 Mcf (34,827 boe) for each of the years ended December 31, 2020, 2019 and 2018, respectively
(3) Operating expenses include operating and transportation expenses

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, 2020, 2019 or 2018. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of
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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.

202020192018
GrossNetGrossNetGrossNet
Exploration
Productive  3.00 2.50 1.00 1.00 
Dry  1.00 1.00 1.00 0.51 
In progress  2.00 2.00 3.00 3.00 
Development
Productive6.00 6.00 22.00 22.00 19.00 18.16 
Dry  2.00 2.00 — — 
In progress1.00 1.00 1.00 1.00 4.00 4.00 
Service
Water injectors1.00 1.00 5.00 5.00 — — 
Total Colombia8.00 8.00 36.00 35.50 28.00 26.67 

Of the three wells in progress in Colombia as at December 31, 2019, one was inactive pending future tests and two were dry at December 31, 2020.

In 2020, we continued work on power reliability and expansion infrastructure in Acordionero and Cohembi fields.

Well Statistics

The following table sets forth our productive wells as of December 31, 2020:

Oil Wells
GrossNet
Colombia (1)
224.0 190.0 
224.0 190.0 

(1) Includes 38.0 gross and 33.1 net water and gas injector wells and 70.0 gross and 67.1 net wells with multiple completions.

We commenced the execution of our 2021 capital program, as planned, and as of February 19, 2021, drilled six development wells and one water injector in the Midas Block



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Developed and Undeveloped Acreage

At December 31, 2020, our acreage was located 93% in Colombia and 7% in Ecuador. The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2020:

Developed
Undeveloped (2)
Total
GrossNetGrossNetGrossNet
Colombia (1)
312,302 219,913 1,544,097 1,534,552 1,856,399 1,754,465 
Ecuador— — 138,239 138,239 138,239 138,239 
Total312,302 219,913 1,682,336 1,672,791 1,994,638 1,892,704 

(1) Excludes our interest in one block with a total of 0.1 million net acres for which government approval of relinquishment or sale was pending at December 31, 2020.
(2) As of December 31, 2020 the exploration phase for 0.3 million gross and net undeveloped acres expires within next three years with an option to extend exploration phase for 50% of the expired area.

Marketing and Major Customers

Colombia represents 100% of our production with oil reserves and production mainly located in the Middle Magdalena Valley (“MMV”) and Putumayo Basin. In MMV, our largest field is the Acordionero Field, where we produce approximately 17° API oil, which represented 49% of total Company production in 2020. The Putumayo production is approximately 27° API for Chaza Block and 18° API for Suoriente Block, which represented 44% of total Company production in 2020.

We have entered into numerous sales agreements for our production from MMV and the Putumayo Basin with domestic and international customers. These agreements are subject to renegotiation terms between three and twelve months and generally contain mutual termination provisions with 90 days' notice. The volume of crude oil contemplated in these sales agreements does not include the volume of oil corresponding to royalties taken in kind, but does include volumes relating to HPR royalties.

The majority of our Putumayo production is sold at wellhead. The oil is picked up by customers at Company operated truck loading stations located at our Costayaco battery or Santana station facilities in Putumayo North, and at our Cohembi and Cumplidor Fields in Putumayo South. Production from the Acordionero Field in MMV is trucked and sold at various terminals or pipeline inlets, and at various distances from the Acordionero field depending on the applicable sales agreement. Production from MMV minor fields is sold at wellhead.

In 2020, approximately 86% of our Putumayo production and 51% of our MMV production was sold to two international marketers, for which the sales agreements expire on August 31, 2021 and June 30, 2021, respectively. The loss of each individual sales customer will not have a material adverse impact on our Company as customers can be substituted.

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, referenced to 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 Colombia's and Ecuador's national oil companies, 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.

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Geographic Information

Based on geographic organization, Colombia is the only reportable segment. During 2019, we signed participation contracts for three blocks in Ecuador. As at and for the years ended December 31, 2020 and 2019, the Ecuador business unit was not significant and was included in our Colombia reportable segment. Long lived assets are Property, Plant and Equipment, which include all oil and gas assets, furniture and fixtures, automobiles, computer equipment and capitalized leases. No long lived assets are held in our country of domicile, which is the United States of America. Assets held by our corporate head office in Calgary, Alberta, Canada were not significant as of December 31, 2020 and 2019 and were included into the Colombia reportable segment under "other" category. Because all of our exploration and development operations are in Colombia and Ecuador, 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 both Colombia and Ecuador 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 LLC, Gran Tierra Colombia Inc. and Gran Tierra Energy Resources Inc. Gran Tierra Energy Colombia LLC and Gran Tierra Colombia Inc. are currently qualified as operators of oil and gas properties by the National Hydrocarbons Regulator ("ANH"). The entities operate under a special regime for hydrocarbon companies in Colombia that entitles them to collect proceeds from oil sales abroad in US dollars.

In Colombia, the ANH is the administrator of the hydrocarbons in the country and therefore is responsible for the administration of Colombian oil and gas contracts and managing all exploration lands. Ecopetrol, the Colombian national oil company, is a public company listed in the Colombian and United States stock markets, 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 directly or through its subsidiaries operates the majority of the oil transportation infrastructure in the country.

The ANH uses various forms of contracts, which provide full risk/reward benefits for the contractor. Under the terms of these contracts, the operator retains the rights to produce all reserves, production and income from any new exploration and evaluation block, subject to existing royalty and tax regulations. Each contract contains an exploration period and a production period. The exploration period contains a number of exploration phases and each phase has an associated work commitment. The production period lasts a number of years (usually 24) from the declaration of a commercial hydrocarbon discovery. Such contracts may be terminated at election of the ANH on the failure of the contract holder to comply with certain material terms of the contract, such as failure to perform committed exploration operations or investments in accordance with the contract.

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.

Ecuador Administration

We operate in Ecuador through the Ecuadorian branch of Gran Tierra Energy Colombia, LLC.

In Ecuador, the Ministry of Energy and Non-Renewable Natural Resources ("MERNNR", for its acronym in Spanish) is responsible for signing the oil and gas contracts and regulating the Ecuadorian oil and gas industry through the Agency for Regulation and Control of Energy and Non-Renewable Natural Resources.

The MERNNR uses Service and Participation Contracts for the Exploration and/or Exploitation of Hydrocarbons. We currently hold three Participation Contracts which provide for full risk for the contractor and production sharing with the MERNNR and contain an exploration period and an exploitation period. The exploration period has an associated work commitment and lasts
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typically 4 years. The exploitation period lasts usually 20 years from the approval of the development plan for a commercial hydrocarbon discovery. Such contracts may be terminated at the election of the MERNNR on the failure of the contract holder to comply with certain material terms of the contract, such as failure to perform committed exploration operations in accordance with the contract.

When operating under a Participation Contract, the contractor is the owner of the hydrocarbons extracted from the contract area during the performance of operations, except for the share of volumes owned by the MERNNR agreed under each contract.

Environmental Compliance

Our activities are subject to laws and regulations governing environmental compliance quality, waste and pollution control in the countries where we maintain operations. Our activities with respect to exploration, drilling, production 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 and Ecuador. Such regulations relate to mandatory 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 licensing and 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 an 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, soil and water testing occur regularly and environmental contingency plans have been prepared for all sites and transportation of oil. We have a regular quarterly reporting system, reporting to executive management as well as an HSE committee of the Board of Directors. We have a schedule of internal and external audits and routine checking of practices and procedures and conduct emergency response exercises.

In 2020, we continued with environmental clean-up activities in the Suroriente Block. The remediation activities address the oil spills originated in 2013 by illegal groups in the area. We are undertaking an estimated total clean-up of 28 hectares of which 21 hectares have already been cleaned up. Activities took place during the first quarter of 2020 and the total amount spent was $1.3 million for the year ended December 31, 2020.

Employees

At December 31, 2020, we had 322 full-time employees (December 31, 2019 - 362): 95 located in the Calgary corporate office, 226 in Colombia (156 staff in Bogota and 70 field personnel), and one in Ecuador (Quito). None of our employees are represented by labor unions, and we consider our employee relations to be good. Safety is one of our greatest priorities, and we have implemented safety management systems, procedures and tools to help protecting our employees and contractors. We strive to hire local employees and have provided training programs for employees, including special programs for women, to develop specialized skills necessary for our industry. We also focus on career development to create opportunities for advancement and strengthened local leadership at our worksites.

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Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (“SEC”). 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 SEC. Our Code of Business Conduct and Ethics, our Corporate Governance Guidelines, our Audit Committee Charter, our Compensation Committee Charter and our Nominating and Corporate Governance Committee Charter are also posted to the governance section of our website. 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 means for distributing information to the public for purposes of compliance with Regulation Fair Disclosure.

In addition, the SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

Item 1A. Risk Factors

Risks Related to our Business

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could cause temporary suspension of production and reduce our value
 
Substantially all of our revenues are derived from the sale of oil. The current and forward contract oil price is based on world demand, supply, weather, pipeline capacity constraints, inventory storage levels, geopolitical unrest, world health events and other factors, all of which are beyond our control. Historically, the market for oil has been volatile and is expected to remain so. During 2020, global oil and natural gas prices declined to historic lows due to a dispute between major oil producing countries combined with the impact of the shutdown in the world economy to mitigate the impact of the COVID-19 pandemic. We expect that oil prices in the near term will continue to be influenced by the duration and severity of the COVID-19 pandemic and its resulting impact on oil and natural gas demand. Furthermore, prices which we receive for our oil sales, while based on international oil prices, are established by contracts with purchasers and include the deductions for transportation and quality differentials. The differentials and transportation costs can change over time and have a detrimental impact on realized prices.

As a result of the low commodity price environment in 2020, we temporarily suspended development and workover activities and operations in fields with low or negative netbacks, which were recommenced in the fourth quarter of 2020. If our production and cash flows decline, it could have a material adverse effect on our results of operations and result in impairments and non-compliance with financial covenants in our debt instruments. For example, for the year ended December 31, 2020, we recorded $102.6 million impairment of goodwill and $564.5 million of oil and gas property and inventory impairment relating to our Colombia business unit. The goodwill impairment was due to the carrying value of the unit exceeding its fair value as a result of the cumulative impact of the shut-in of uneconomic oil production in and lower forecasted commodity prices. The oil and gas property impairment was a result of the net book value of oil and gas assets in our Colombia business unit, less related deferred income taxes, exceeding a calculated “ceiling”.

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

We may be adversely affected by global epidemics, including the recent COVID-19 pandemic

The outbreak of the COVID-19 virus, which was declared a pandemic by the World Health Organization, has spread across the globe and impacted worldwide economic activity since early 2020. Governments worldwide, including those in Colombia and Ecuador, the countries where we operate, enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods and social distancing, have caused material disruption to businesses globally resulting in an economic slowdown. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions however the long-term success of these interventions is not currently determinable. In addition, global commodity prices declined significantly in 2020 due to the dramatic decline in demand for oil and natural gas, coupled with oversupply in the midst of a dispute between OPEC and other major oil producing countries. Despite the recent improvement in oil prices, this challenging economic climate has had and may in the future have significant adverse impacts on our Company including, but not exclusively:
material declines in revenue and cash flows as a result of the decline in commodity prices;
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declines in revenue and operating activities due to reduced capital programs and the shut-in of production;
impairment charges;
inability to comply with covenants and restrictions in debt agreements;
inability to access financing sources;
increased risk of non-performance by our customers and suppliers; and
interruptions in operations as we adjust personnel to the dynamic environment.

The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on our Company is not fully known at this time. Estimates and judgments made by management in the preparation of the financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period. The pandemic and resulting worldwide economic downturn could create risks we have not identified or amplify the impact of other risks we have identified.

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 operating and transportation 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 identify and retain responsible service providers and contractors to efficiently drill and complete our wells and to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

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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 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 proved 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, blockades, 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.

Both Colombia and Ecuador have 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. Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Ecuador or 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 four fields located in Colombia. For the year ended December 31, 2020, the Acordionero, Costayaco, Moqueta and Cohembi Fields collectively generated 90% of our production and at December 31, 2020, these four fields accounted for 88% 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 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.

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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. In 2020 we experienced a local farmers blockade at Suroriente and PUT-7 Blocks, which has negatively impacted our annual production. The local farmers blockade has been resolved at the end of the third quarter of 2020.

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 of 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. We also cannot ensure that we will not experience protests or blockades erected by criminal groups or cultivators of illegal crops, in response to the Colombian government's eradication of such crops, if such crops are grown in proximity to roads required to access our operations. In addition, we must comply with legislative requirements for prior consultation with communities and ethnic groups who are affected by our proposed projects in Colombia and Ecuador. 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 and essential referendums on extractive industries. The referendums were organized by opponents of the mining or oil and natural gas industries. It remains unclear to what extent such results can impact the exercise of mineral rights conferred by the national government.

Security concerns in Colombia or Ecuador may disrupt our operations

Oil pipelines have historically been primary targets of terrorist activity in Colombia. Although a Peace Agreement was ratified by Colombian government in 2016, the result of which was the demobilization and disarmament of the Revolutionary Armed Forces of Colombia ("FARC"), there continue to be examples of violence against pipelines and other infrastructure that has been attributed to such FARC groups. 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 ratified and the ongoing efforts to implement such Agreements as well as 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 and Ecuador also both have 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 and Quito head office personnel or operations in Colombia and Ecuador 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.

All 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

All 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
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permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.

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.

We hold a minority equity investment in PetroTal Corp. ("PetroTal"), 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. 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 us 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. Serving 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. We may also be limited in our ability to monetize or exit our investment in PetroTal given the limited trading market for its equity securities. Subsequent to December 31, 2020, we sold 44% percent of our interest in PetroTal with the remaining investment representing 17% of PetroTal's issued and outstanding common shares.

Risks Related to our Financial Condition

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

Our base capital program for 2021 is $130.0 million to $150.0 million for exploration and development based on a mid-point range for budgeted exploration costs. We expect to finance our 2021 capital program primarily through cash flows from
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operations. Funding this program from cash flows from operations relies in part on Brent oil prices being at least $49.0 per barrel or greater. For the period from January 1 to February 19, 2021, the average price of Brent oil was $57.8 per barrel.

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 reserves.

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, including in Colombia and Ecuador, 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 flows 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 $215 million, of which $200 million is readily available for borrowing and $15 million is subject to approval by majority lenders. Our borrowing base is redetermined by the lenders twice per year, with the next re-determination to occur no later than May 2021. 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, lenders willingness to lend to the oil and gas industry, 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 would 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. Management has obtained a relief from compliance with certain financial covenants until October 1, 2021 ("the covenant relief period"), permitting the ratio of total debt to Covenant EBITDAX ("EBITDAX") to be greater than 4.0 to 1.0, Senior Secured Debt to EBITDAX ratio must not exceed 2.5 to 1.0, and EBITDAX to interest expense ratio for the trailing four quarter periods measured as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, must be at least 1.5 to 1.0 (ii) June 30, 2021 and September 30, 2021 must be at least 2.0 to 1.0, and be at least 2.5 to 1.0 thereafter. We are required to comply with various covenants, which as disclosed above, have been modified in response to the current market conditions and the COVID-19 pandemic. After the expiration of covenant relief period, we must maintain compliance with the following financial covenants: limitations on Company's ratio of debt to EBITDAX to a maximum of 4.0 to 1.0; limitations on Company's ratio of Senior Secured Debt to EBITDAX to a maximum of 3.0 to 1.0; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0.

If we fail to comply with these financial covenants, it would result in a default under the terms of the credit agreement, which could result in an acceleration of repayment of all indebtedness under our revolving credit facility. An event of default under the revolving credit facility would result in a default under the indentures governing our senior notes, which could allow the note holders to require us to repurchase all of our outstanding senior notes. Based on the Brent price and production levels used in
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2021 outlook, management expects to be in compliance with the financial covenants contained in the credit facility agreement after the expiry of covenant relief period.

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 assets and 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 U.S. dollars, we must translate revenues, expenses and income, as well as assets and liabilities, into U.S. dollars 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 also hold an equity stake in PetroTal (TSXV - TAL, AIM - PTAL) which is denominated in Canadian dollars. Changes in exchange rate impacts the value of our investment.

Legal and Regulatory Risks

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 may 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 of 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 and Ecuador 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.

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
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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.

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, Ecuador 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 or Ecuador 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.

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. 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, there have been efforts in recent years to influence the investment community to consider climate change in how they invest in companies. 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.

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Risks Related to Ownership of our Common Stock

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.

If we cannot meet the NYSE American continued listing requirements, the NYSE may delist our shares of Common Stock

Our shares of Common Stock are currently listed on the NYSE American, and the continued listing of our shares is subject to our compliance with a number of listing standards. If we fail to maintain compliance with these continued listing standards, including if the price our shares of Common Stock remains at its current low for a substantial period of time and we fail to effect a reverse stock split upon notice from the NYSE, our shares of Common Stock may be delisted. A delisting of our shares could negatively impact us by, among other things reducing the liquidity of our shares and limiting our ability to issue additional securities, obtain additional financing or pursuant strategic transactions.

For as long as we are a smaller reporting company, we will not be required to comply with certain disclosure requirements that apply to other public companies

We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act. “Smaller reporting companies”, are able to provide simplified executive compensation disclosures in their filings, and have certain other scaled disclosure obligations in their SEC filings, including, among other things, being required to provide only two years of audited financial statements in annual reports. The scaled disclosures we provide in our SEC filings due to our status as a “smaller reporting company” may make it harder for investors to analyze our results of operations and financial prospects. If some investors find our common stock to be less attractive as a result of the scaled disclosures, there also may be a less active trading market for our common stock and our trading price may be more volatile.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings
 
We are engaged in discussions with the ANH 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. Although the outcome of these discussions cannot be predicted with certainty, we believe the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. The costs are recorded as they incurred or become probable and determinable.

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.

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Information About Our Executive Officers

Set forth below is information regarding our executive officers as of February 19, 2021.

NameAgePosition
Gary S. Guidry65President and Chief Executive Officer, Director
Ryan Ellson45Chief Financial Officer and Executive Vice President, Finance
James Evans55Vice President, Corporate Services
Glen Mah64Vice President, Exploration Ecuador
Rodger Trimble59Vice President, Investor Relations
Lawrence West64Vice President, Exploration

Gary S. Guidry, President and Chief Executive Officer, Director. Mr. Guidry has been Gran Tierra's Chief Executive Officer and President since May 7, 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 and Executive Vice President, Finance. Mr. Ellson has been Gran Tierra's Chief Financial Officer since May 2015. Mr. Ellson has over 21 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). 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. Glencore E&P (Canada) purchased Caracal in 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 reserve based lending facility's 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. Mr. Ellson has completed the Leadership for Senior Executives program at Harvard Business School and several executive education programs at The Wharton School of the University of Pennsylvania.

James Evans, Vice President, Corporate Services. Mr. Evans has been Gran Tierra's Vice President, Corporate Services, since May 2015. Mr. Evans has over 27 years of experience including working the last 16 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 holds a Bachelor of Commerce degree from the University of Calgary.

Glen Mah, Vice President, Exploration Ecuador. Mr. Mah was appointed as Vice President, Explorations Ecuador in September 2019 and 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
27


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.

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 31 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 36 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 19, 2021, there were approximately 28 holders of record of shares of our Common Stock and 366,981,556 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”).

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. As a smaller reporting
28


company, we are not required to include information regarding fiscal year 2018 in this Item 7, including a comparison of 2019 to 2018. For this information, please read Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, in our Annual Report on Form 10-K for the year ended December 31, 2019.

Overview

We are a company focused on international oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 100% of our proved reserves NAR at December 31, 2020. For the year ended December 31, 2020, 100% of our revenue was generated in Colombia (2019 - 100%). We are headquartered in Calgary, Alberta, Canada.

As of December 31, 2020, we had estimated proved reserves NAR of 65.0 MMBOE, a slight decrease of 4% from the prior year, of which 60% were proved developed reserves and 100% were oil.

Financial and Operational Highlights

Key Highlights

Net loss in 2020 was $778.0 million or $(2.12) per share basic and diluted, which included a non-cash ceiling test and inventory impairment of $564.5 million and goodwill impairment of $102.6 million, respectively, compared to net income of $38.7 million, or $0.10 per share basic and diluted in 2019
Loss before income taxes in 2020 was $853.4 million compared to income before income taxes of $96.0 million in 2019
Our total 2020 average production NAR was 20,072 bopd, a decrease from 29,015 bopd in 2019. With unprecedented impact of the COVID-19 pandemic and the related crash in world oil prices, we took decisive action during the first half of 2020 to shut-in minor fields, curtail drilling activity and defer workovers in order to protect the Company's balance sheet and liquidity. In the low price environment, we made the prudent move not to maximize production but defer production to a higher price environment
Our total 2020 oil sales volumes NAR decreased by 31% to 20,163 bopd compared to 2019
Oil sales for 2020 decreased 58% to $237.8 million compared to $571.0 million in 2019 primarily as a result of a 33% decrease in Brent price and a 31% decrease in sales volumes
Oil sales per bbl for 2020 were $32.23, 40% lower compared to 2019
Adjusted EBITDA(1) for 2020 was $96.5 million compared to $329.4 million in 2019
Funds flow from operations(1) for 2020 decreased by 83% to $45.2 million or $0.12 per share basic and diluted compared with $272.4 million or $0.72 per share basic and diluted in 2019
Operating expenses per bbl for 2020 were $15.16, 12% lower compared to 2019 primarily due to cost saving initiatives implemented during the first half of 2020 in response to deteriorating world oil prices, and the shut-in of higher cost minor fields for a portion of 2020. The majority of the cost saving initiatives, which are expected to be maintained in 2021, represent structural improvements of the Company's operations. Total operating expenses were $111.9 million in 2020, compared to $183.2 million in 2019 representing a 39% decrease
Quality and transportation discounts per bbl for 2020 were $10.98 compared to $10.48 in 2019. The increase was due to higher Castilla and Vasconia differentials in 2020 compared to 2019
Transportation expenses per bbl for 2020 decreased by 26% to $1.43 compared to 2019, primarily as a result of utilization of alternative transportation routes during 2020 which had lower cost per bbl
General and administrative ("G&A") expenses before stock-based compensation per bbl for 2020 decreased by 3% to $3.05 compared to 2019 due to headcount optimization in addition to costs saving initiatives implemented in 2020, despite a 31% decrease in production. G&A expense before stock-based compensation was $22.5 million in 2020, compared to $33.3 million in 2019 representing a 32% decrease
Capital expenditures decreased by $283.0 million or 75% from the prior year to $96.3 million as a result of significantly reduced activity. During fourth quarter of 2020, we restarted development drilling operations at the Acordionero field and accelerated certain budgeted first half of 2021 capital expenditures into fourth quarter to maximize operational efficiencies
In December 2020, we completed the semi-annual redetermination of our credit facility resulting in a committed borrowing base of $215.0 million with a balance outstanding of $190.0 million as at December 31, 2020
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Through both direct tax refunds from the Colombian government and value-added tax ("VAT) on our oil sales, we collected a total of VAT and income tax receivables of $113.7 million

(Thousands of U.S. Dollars, unless otherwise noted)Year Ended December 31,
2020% Change2019
SEC Compliant Reserves, NAR (MMBOE)
Estimated proved oil and gas reserves65 (4)68 
Estimated probable oil and gas reserves44 (24)58 
Estimated possible oil and gas reserves44 16 38 
Average Consolidated Daily Volumes (BOPD)
Working interest ("WI") production before royalties22,624 (35)34,817 
Royalties(2,552)(56)(5,802)
Production NAR20,072 (31)29,015 
Decrease in inventory91 (27)125 
Sales (2)
20,163 (31)29,140 
Net (Loss) Income
$(777,967)(2,111)$38,690 
Operating Netback
Oil sales$237,838 (58)$570,983 
Operating expenses(111,888)(39)(183,204)
Transportation expenses(10,543)(48)(20,400)
Operating netback (1)
$115,407 (69)$367,379 
G&A Expenses Before Stock-Based Compensation$22,506 (32)$33,300 
G&A Stock-Based Compensation$1,216 (15)$1,430 
Adjusted EBITDA (1)
$96,482 (71)$329,359 
Net Cash Provided By Operating Activities$81,074 (54)$177,665 
Funds Flow From Operations (1)
$45,213 (83)$272,409 
Capital Expenditures$96,281 (75)$379,314 
Cash Paid for Acquisitions, Net of Cash Acquired$ (100)$77,772 

 As at December 31,
(Thousands of U.S. Dollars)2020% Change2019
Cash and cash equivalents and current restricted cash and cash equivalents$14,114 60 $8,817 
Working capital surplus, including cash and cash equivalents
$20,226 (78)$91,347 
Revolving credit facility$190,000 61 $118,000 
Senior Notes$600,000 — $600,000 

(1) Non-GAAP measures

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

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Operating netback, as presented, is defined as oil sales less operating and transportation expenses. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil 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 or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for asset impairment, goodwill impairment, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, loss on redemption of Convertible Notes, unrealized gains or losses on financial instruments, other non-cash losses and stock based compensation expense. 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 or loss to EBITDA and adjusted EBITDA is as follows:

 Year Ended December 31,Three Months Ended,
December 31, December 31, September 30,
(Thousands of U.S. Dollars)20202019202020192020
Net (loss) income$(777,967)$38,690 $(47,871)$27,004 $(107,821)
Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
DD&A expenses164,233 225,033 33,115 60,603 31,340 
Interest expense54,140 43,268 13,936 12,613 14,029 
Income tax (recovery) expense(75,394)57,285 (13,158)11,610 (20,565)
EBITDA (non-GAAP)$(634,988)$364,276 $(13,978)$111,830 $(83,017)
Asset impairment564,495 — 57,402 196 104,731 
Goodwill impairment102,581 —  — — 
Non-cash lease expense1,951 1,806 457 440 523 
Lease payments(1,926)(1,969)(522)(366)(429)
Unrealized foreign exchange loss (gain)5,271 1,803 (17,064)(3,500)3,080 
Loss on redemption of Convertible Notes 11,501  196 — 
Unrealized loss (gain) on financial instruments55,856 (49,488)(5,983)(44,323)(5,086)
Other non-cash loss2,026 —  — 2,026 
Stock-based compensation expense1,216 1,430 1,923 338 56 
Adjusted EBITDA (non-GAAP)$96,482 $329,359 $22,235 $64,811 $21,884 

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, asset impairment, goodwill impairment, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, financial instruments gains or losses, other non-cash losses, cash settlement of financial instruments and loss on redemption of Convertible Notes. 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:
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 Year Ended December 31,Three Months Ended,
December 31, December 31, September 30,
(Thousands of U.S. Dollars)20202019202020192020
Net (loss) income
$(777,967)$38,690 $(47,871)$27,004 $(107,821)
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses164,233 225,033 33,115 60,603 31,340 
Asset impairment564,495 — 57,402 — 104,731 
Goodwill impairment102,581 —  — — 
Deferred tax (recovery) expense(76,148)40,227 (13,352)8,475 (21,202)
Stock-based compensation expense 1,216 1,430 1,923 338 56 
Amortization of debt issuance costs3,625 3,376 851 802 838 
Non-cash lease expense1,951 1,806 457 440 523 
Lease payments(1,926)(1,969)(522)(366)(429)
Unrealized foreign exchange loss (gain)5,271 1,803 (17,064)(3,500)3,080 
Other non-cash loss2,026 —  — 2,026 
Financial instruments loss (gain)50,982 (46,215)(887)(43,325)(713)
Cash settlement of financial instruments4,874 (3,273)(5,096)(998)(4,373)
Loss on redemption of Convertible Notes 11,501  196 — 
Funds flow from operations (non-GAAP)$45,213 $272,409 $8,956 $49,669 $8,056 

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

Consolidated Results of Operations

 Year Ended December 31,
(Thousands of U.S. Dollars)2020% Change2019
Oil sales$237,838 (58)$570,983 
Operating expenses111,888 (39)183,204 
Transportation expenses10,543 (48)20,400 
Operating netback (1)
115,407 (69)367,379 
COVID-19 related costs2,679 100 — 
DD&A expenses164,233 (27)225,033 
Asset impairment564,495 100 — 
Goodwill Impairment102,581 100 — 
G&A expenses before stock-based compensation22,506 (32)33,300 
G&A stock-based compensation expense1,216 (15)1,430 
Severance expenses1,628 (8)1,771 
Foreign exchange loss4,184 567 627 
Financial instruments loss (gain)50,982 210 (46,215)
Interest expense54,140 25 43,268 
968,644 274 259,214 
Other loss(469)(96)(12,886)
Interest income345 (50)696 
(Loss) income before income taxes(853,361)(989)95,975 
Current income tax expense754 (96)17,058 
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Deferred income tax (recovery) expense(76,148)(289)40,227 
Total income tax (recovery) expense(75,394)(232)57,285 
Net (loss) income$(777,967)(2,111)$38,690 
Sales Volumes (NAR)
Total sales volumes, BOPD20,163 (31)29,140 
Brent Price per bbl$43.21 (33)$64.16 
Consolidated Results of Operations per bbl Sales Volumes (NAR)
Oil sales$32.23 (40)$53.68 
Operating expenses15.16(12)17.23
Transportation expenses1.43(26)1.92
Operating netback (1)
15.64(55)34.53
COVID-19 related costs0.36100 
DD&A expenses22.2521.16
Asset impairment76.49100 — 
Goodwill Impairment13.90100 
G&A expenses before stock-based compensation3.05(3)3.13
G&A stock-based compensation expense0.1623 0.13
Severance expenses0.2229 0.17
Foreign exchange loss0.57850 0.06
Financial instruments loss (gain)6.91259 (4.35)
Interest expense7.34 80 4.07
131.25439 24.37
Other loss(0.06)95 (1.21)
Interest income0.05 (29)0.07 
(Loss) income before income taxes(115.62)(1,382)9.02 
Current income tax expense0.10(94)1.60
Deferred income tax (recovery) expense(10.32)(373)3.78
Total income tax (recovery) expense(10.22)(290)5.38
Net (loss) income$(105.40)(2,996)$3.64 

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

Oil Production and Sales Volumes, BOPD

Year Ended December 31,
Average Daily Volumes (BOPD) 20202019
WI production before royalties22,624 34,817 
Royalties(2,552)(5,802)
Production NAR20,072 29,015 
Decrease in inventory91 125 
Sales20,163 29,140 
Royalties, % of working interest production before royalties11 %17 %

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Oil production NAR for the year ended December 31, 2020 decreased 31% to 20,072 BOPD from 2019. With unprecedented impact of the COVID-19 pandemic and the related crash in world oil prices, we took decisive action during the first half of 2020 to shut-in minor fields, curtail drilling activity and defer workovers in order to protect the Company's balance sheet and liquidity. In the low price environment, we made the prudent move not to maximize production but defer production to a higher price environment. In addition, we experienced force majeure related to local farmers blockade which resulted in shut-in of production at the Suroriente and PUT-7 Blocks for the first half of 2020.

Royalties as a percentage of production for the year ended December 31, 2020, decreased compared to prior year commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.


gte-20201231_g2.jpg

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gte-20201231_g3.jpg
The Midas Block includes Acordionero, Mochuelo and Ayombero-Chuira fields and the Chaza Block includes Costayaco and Moqueta fields.

Oil Sales

Oil sales for the year ended December 31, 2020, decreased by 58% to $237.8 million compared to $571.0 million in 2019, primarily as a result of a 33% decrease in Brent price and lower production volumes.

The following table shows the effect of changes in realized price and sales volumes on our oil sales for the two years ended December 31, 2020:

Year Ended December 31,
(Thousands of U.S. Dollars)20202019
Oil sales for the comparative period $570,983 $613,431 
Realized sales price decrease effect(158,334)(51,485)
Sales volume (decrease) increase effect(174,811)9,037 
Oil sales for the current period$237,838 $570,983 

On a per bbl basis, average realized prices decreased by 40% to $32.23 for the year ended December 31, 2020 compared to $53.68 in 2019, primarily as a result of the decrease in benchmark oil prices and higher Castilla and Vasconia differentials in 2020. In 2020 Castilla and Vasconia differentials per bbl averaged $6.79 and $4.31 respectively, compared to $5.64 and $2.54 respectively, in 2019.

Transportation Expenses

We have options to sell our oil through multiple pipelines and trucking routes. Each transportation route has varying effects on realized price and transportation expenses. The following table shows the percentage of oil volumes we sold in Colombia using each transportation method for each of the two years ended December 31, 2020:
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Year Ended December 31,
20202019
Volume transported through pipelines4 %%
Volume sold at wellhead48 %51 %
Volume transported via truck to pipelines48 %48 %
100 %100 %

Volumes transported through pipelines or via truck receive a higher realized price, but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense. We focus on maximizing operating netback per bbl when choosing a transportation method.

Transportation expenses for the year ended December 31, 2020, decreased by 48% to $10.5 million, compared with $20.4 million in 2019, as a result of lower sales volumes and the utilization of alternative transportation routes during 2020. On a per bbl basis, transportation expenses decreased 26% to $1.43, from $1.92 in 2019. The decrease in transportation expenses per bbl was as a result of utilization of alternative transportation routes during 2020 which had lower cost per bbl compared to the corresponding period in 2019.
gte-20201231_g4.jpg

The following table shows the variance in our average realized price net of transportation expenses in Colombia for each of the two years ended December 31, 2020:

Year Ended December 31,
(U.S. Dollars per bbl Sales Volumes NAR)20202019
Average realized price net of transportation expenses for the comparative period$51.76 $55.76 
Decrease in benchmark prices(20.95)(7.53)
(Increase) decrease in quality and transportation discounts(0.50)2.68 
Decrease in transportation expense0.49 0.85 
Average realized price net of transportation expenses for the year$30.80 $51.76 


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Operating Expenses

Operating expenses for the year ended December 31, 2020, decreased by 39% to $111.9 million compared to $183.2 million in 2019. On a per bbl basis, operating expenses decreased by $2.07 to $15.16 compared to $17.23 in the prior year, primarily due to cost saving initiatives implemented during the first half of 2020 in response to deteriorating world oil prices, and the shut-in of higher cost minor fields for a portion of 2020. The majority of the cost saving initiatives, which are expected to be maintained in 2021, represent structural improvements of the Company's operations. By the end of fourth quarter of 2020, we resumed development activities throughout our portfolio at much lower cost, including the ongoing workover operations and restart of development drilling at Acordionero, the restart of workover operations at Costayaco, and the restart of previously shut-in minor fields.

gte-20201231_g5.jpg
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Operating Netbacks

Year Ended December 31,
Consolidated20202019
(Thousands of U.S. Dollars)
Oil sales$237,838 $570,983 
Transportation expenses(10,543)(20,400)
227,295 550,583 
Operating expenses(111,888)(183,204)
Operating netback (1)
$115,407 $367,379 
(U.S. Dollars per bbl Sales Volumes NAR)
Brent$43.21 $64.16 
Quality and transportation discounts(10.98)(10.48)
Average realized price32.23 53.68 
Transportation expenses(1.43)(1.92)
Average realized price net of transportation expenses30.80 51.76 
Operating expenses(15.16)(17.23)
Operating netback (1)
$15.64 $34.53 

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



gte-20201231_g6.jpg
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gte-20201231_g7.jpg

COVID-19 Related Costs

The COVID-19 pandemic resulted in extra operating and transportation costs related to COVID-19 health and safety preventative measures including incremental sanitation requirements and enhanced procedures for trucking barrels and crew changes in the field. For the year ended December 31, 2020, COVID-19 costs were $2.5 million relating to operating activities and $0.2 million to transportation activities. There were no COVID-19 related costs in 2019.

DD&A Expenses

Year Ended December 31,
20202019
DD&A Expenses, Thousands of U.S. Dollars $164,233 $225,033 
DD&A Expenses, U.S. Dollars per bbl$22.25 $21.16 

DD&A expenses for the year ended December 31, 2020, decreased by 27%, and increased by 5% on a per bbl from 2019. On a per bbl basis, the DD&A increase in 2020 was due to a proportionally higher decrease in production, compared to the decrease in overall DD&A expense, when compared to 2019.

Asset Impairment

Year Ended December 31,
(Thousands of U.S. Dollars)20202019
Impairment of oil and gas properties$560,344 $— 
Impairment of inventory4,151 — 
$564,495 $— 

We follow the full cost method of accounting for our oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted
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future net revenues, oil and natural gas prices are determined using the average price during the 12-month period prior to the ending date of the period covered by the balance sheet, calculated as an unweighted arithmetic average of the first-day-of-the month price for each month within such period for that oil and natural gas. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of our reserves.

For the year ended December 31, 2020, $560.3 million ceiling test impairment was recorded in our Colombia cost center. In accordance with GAAP, we used an average Brent price of $43.43 per bbl less corresponding differentials for the purpose of the December 31, 2020 ceiling test calculation (2019 - $64.20). For the year ended December 31, 2019, no ceiling test impairment was recorded.

For the year ended December 31, 2020, we recorded $4.2 million relating to the impairment of oil inventory due to the decline in commodity pricing. There was no inventory impairment for the year ended December 31, 2019.

Goodwill Impairment

For the year ended December 31, 2020, we recorded $102.6 million of goodwill impairment relating to our Colombia business unit. The impairment was due to the carrying value of the unit exceeding its fair value as a result of the cumulative impact of the shut-in of higher cost production fields and lower forecasted commodity prices. The estimated fair value of the Colombia unit for the goodwill impairment test was based on the discounted after-tax cash flows associated with the proved and probable reserves of the reporting unit. Our goodwill consisted entirely of $102.6 million relating to the Solana Resources Limited and Argosy Energy International L.P. acquisitions in 2008 and 2006, respectively. There was no goodwill impairment for the year ended December 31, 2019.

G&A Expenses

(Thousands of U.S. Dollars)Year Ended December 31,
2020% change2019
G&A expenses before stock-based compensation$22,506 (32)$33,300 
G&A stock-based compensation1,216 (15)1,430 
G&A expenses, including stock-based compensation$23,722 (32)$34,730 
(U.S. Dollars Per bbl Sales Volumes NAR)
G&A expenses before stock-based compensation$3.05 (3)$3.13 
G&A stock-based compensation0.16 23 0.13 
G&A expenses, including stock-based compensation$3.21 (2)$3.26 

G&A expenses before stock-based compensation for the year ended December 31, 2020 decreased 32% compared to 2019 due to headcount optimization and cost saving measures implemented in 2020. On a per bbl basis, G&A expenses before stock-based compensation decreased 3% to $3.05 compared to 2019, despite a 31% decrease in production.

G&A expenses after stock-based compensation for the year ended December 31, 2020 decreased 32% for the same reason mentioned above, as well as lower stock based compensation as a result of lower share price compared to 2019. On a per bbl basis G&A expenses after stock based compensation were lower compared to prior year at $3.21, consistent with 31% lower production.






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gte-20201231_g8.jpg

Severance Expenses

For the years ended December 31, 2020 and 2019, severance expenses were $1.6 million and $1.8 million, respectively, due to headcount optimization.

Foreign Exchange Losses

For the years ended December 31, 2020 and 2019, we had foreign exchange losses of $4.2 million and $0.6 million, respectively. The main sources of the foreign exchange losses are revaluation of investment in PetroTal shares, taxes receivable and payable, and deferred tax assets and liabilities. Under GAAP, investment, income taxes and deferred taxes are considered a monetary assets and liabilities and require translation from local currency to U.S. dollar functional currency at each balance sheet date.

The following table presents the change in the Colombian peso and Canadian dollar against the U.S. dollar for the last two years ended December 31, 2020 and 2019:

Year Ended December 31,
20202019
Change in the Colombian peso against the U.S. dollarweakened byweakened by
5 %%
Change in the Canadian dollar against the U.S. dollarstrengthened bystrengthened by
2 %%

Financial Instruments Gains or Losses

The following table presents the nature of our financial instruments gains or losses for the last two years ended December 31:
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Year Ended December 31,
(Thousands of U.S. Dollars)20202019
Commodity price derivative (gain) loss$(220)$3,642 
Foreign currency derivative loss3,155 27 
Investment loss (gain)46,883 (49,884)
Financial instruments loss1,164 — 
$50,982 $(46,215)

For the year ended December 31, 2020, we had an unrealized investment loss of $46.9 million (2019 - unrealized investment gain of $49.9 million) on our investment in PetroTal. On January 21, 2021, we disposed 44% of our interest in PetroTal for a cash consideration of $14.8 million and incurred loss on sale of $5.1 million.

Income Tax Expense and Recovery

Year Ended December 31,
(Thousands of U.S. Dollars)20202019
(Loss) income before income taxes$(853,361)$95,975 
Current income tax expense$754 $17,058 
Deferred income tax (recovery) expense(76,148)40,227 
Total income tax (recovery) expense$(75,394)$57,285 
Effective tax rate9 %60 %

Current income tax expense decreased for the year ended December 31, 2020, compared to 2019, primarily as a result of lower taxable income in Colombia.

The deferred income tax recovery for the year ended December 31, 2020, of $76.1 million was mainly a result of an impairment write-down in Colombia, which was partially offset by Colombian tax losses that are now fully offset by a valuation allowance. The deferred income tax expense for the year ended December 31, 2019, of $40.2 million was primarily a result of excess tax depreciation compared to accounting depreciation in Colombia.

Our effective tax rate was 9% for the year ended December 31, 2020, compared with 60% in 2019. The decrease in the effective tax rate was primarily due to an increase in valuation allowance, increase in foreign currency translation adjustment, goodwill impairment, and impact of foreign taxes.
The difference between our effective tax rate of 9% for the year ended December 31, 2020, and the 32% Colombian statutory rate was primarily due to an increase in the valuation allowance, foreign currency translation adjustment, non-deductible goodwill impairment, and impact of foreign taxes.

The difference between our effective tax rate of 60% for the year ended December 31, 2019, and the 33% Colombian statutory rate was primarily due to an increase in foreign currency translation adjustments, impact of foreign taxes, other permanent differences, valuation allowance and non-deductible third party royalties in Colombia. These are partially offset by a non-taxable investment gain.

Our estimated tax pools at December 31, 2020, are as follows:

(Thousands of U.S. Dollars)2020
Colombia
   Non-capital losses and other tax credits$252,032 
   Depletable and depreciable assets902,519 
Total tax pools and credits$1,154,551 

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

(Thousands of U.S. Dollars)
Fourth quarter 2020 compared with third quarter 2020
% change
Fourth quarter 2020 compared with fourth quarter 2019
% change
Year ended December 31, 2020 compared with year ended December 31, 2019
% change
Net (loss) income for the comparative period
$(107,821)$27,004 $38,690 
Increase (decrease) due to:
Sales volumes7,617 (38,147)(174,811)
Prices4,034 (24,994)(158,334)
Expenses:
Cash operating expenses(6,494)21,845 71,316 
Transportation(708)2,239 9,857 
COVID-19 related costs(42)(1,150)(2,679)
Cash G&A, excluding stock-based compensation expense(817)3,195 10,794 
Severance(37)530 143 
Interest, net of amortization of debt issuance costs106 (1,274)(10,623)
Realized foreign exchange gain (loss)41 (2,608)(89)
Settlement of financial instruments(723)(4,098)8,147 
Other (loss) gain(2,361)983 2,942 
Current taxes443 2,941 16,304 
Net lease payments(159)(139)188 
Interest income— (36)(351)
Net change in funds flow from operations (1) from comparative period
900 (40,713)(227,196)
Expenses:
Depletion, depreciation and accretion(1,775)27,488 60,800 
Goodwill impairment— — (102,581)
Asset impairment47,329 (57,402)(564,495)
Deferred tax(7,850)21,827 116,375 
Amortization of debt issuance costs(13)(49)(249)
Loss on convertible notes— 196 11,501 
Net lease payments159 139 (188)
Stock-based compensation(1,867)(1,585)214 
Other non-cash gain (loss)2,026 — (2,026)
Financial instruments gain (loss), net of financial instruments settlements897 (38,340)(105,344)
Unrealized foreign exchange20,144 13,564 (3,468)
Net change in net loss
59,950 (74,875)(816,657)
Net loss for the current period
$(47,871)56 %$(47,871)(277)%$(777,967)(2,111)%

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


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2021 Work Program and Capital Expenditures
 
Our Colombian operation, which represents 100% of our production, is expected to represent 98% of our 2021 capital budget with the remainder allocated to exploration activities in Ecuador.

The table below shows the break-down of our 2021 capital program:

Number of Wells
(Gross)
Number of Wells
(Net)
2021 Capital Budget
($ million)
Colombia
Development14-1814-18118-138
Exploration— — 9
Ecuador
Exploration— — 3
14-1814-18
130-150

Our base capital program for 2021 is $130 million to $150 million for exploration and development based on a mid-point range for budgeted exploration costs. Based on the mid-point of the 2021 guidance, the capital budget is forecasted to be approximately 91% directed to development and 9% to exploration activities. Approximately 21% of the development activities included in the 2021 capital program are expected to be directed to facilities.

We expect our 2021 capital program to be fully funded by cash flows from operations. Funding this program from cash flow from operations relies in part on Brent oil prices being at least $49 per bbl for 2021.

Capital Program

Capital expenditures during the year ended December 31, 2020, were $96.3 million.

During the year ended December 31, 2020, we spud the following wells in Colombia:

Number of Wells
(Gross and Net)
Development7.0 
Service 1.0 
Total 8.0 
 
We spud one service, and 7 development wells in 2020. All of the wells were in the Midas Block.

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Liquidity and Capital Resources

 As at December 31,
(Thousands of U.S. Dollars)2020% Change2019
Cash and cash equivalents$13,687 65 $8,301 
Current restricted cash and cash equivalents$427 (17)$516 
Working capital surplus, including cash and cash equivalents
$20,226 (78)$91,347 
Revolving credit facility$190,000 61 $118,000 
Senior Notes$600,000 — $600,000 

The outbreak of the COVID-19 virus, which was declared a pandemic by the World Health Organization, has spread across the globe and impacted worldwide economic activity. In addition, global commodity prices declined significantly due to disputes between major oil producing countries combined with the impact of the COVID-19 pandemic and associated reductions in global demand for oil. Governments worldwide, including those in Colombia and Ecuador, the countries where we operate, enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods and social distancing, have caused, and may continue to cause, material disruption to businesses globally resulting in an economic slowdown. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions however the success of these interventions is not currently determinable. The current challenging economic climate is having and may continue to have significant adverse impacts on our Company including, but not exclusively:
material declines in revenue and cash flows as a result of the decline in commodity prices;
declines in revenue and operating activities due to reduced capital programs and the shut-in of production;
impairment charges;
inability to comply with covenants and restrictions in debt agreements;
inability to access financing sources;
increased risk of non-performance by our customers and suppliers;
interruptions in operations as we adjust personnel to the dynamic environment; and
inability to operate or delay in operations as a result COVID-19 restrictions in the countries in which we operate

The unprecedented decline in oil prices has materially reduced our forecasted EBITDAX and the estimated value of our oil reserves. Based on current forecasted Brent pricing and production levels, which can change materially in very short time frames, we forecasted to be in compliance with the amended financial covenants contained in Senior Secured Credit Facility ("the revolving credit facility") for at least the next year from the date of these financial statements. The amount available under the revolving credit facility is based on the lenders determination of the borrowing base. The borrowing base is determined, by the lenders, based on our reserves and commodity prices. The next renewal of the borrowing base is scheduled for May 2021 and there is risk that the borrowing base may be reduced by the lenders. In addition, our ability to borrow under the credit facility may be limited by the terms of the indentures for the 6.25% Senior Notes and 7.75% Senior Notes.

The risk of non-compliance with the covenants in the lending agreements and the risk associated with maintaining the borrowing base is heightened in the current period of volatility coupled with the unprecedented disruption caused by the COVID-19 pandemic. Management currently expects that we will continue to meet the terms of the revolving credit facility or obtain further amendments or waivers if and when required. We also expect to be able to maintain the borrowing base at a level in excess of the amount borrowed. However, there can be no assurances that our liquidity can be maintained at or above current levels during this period of volatility and global economic uncertainty.
The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on our Company is not known at this time.
On June 1, 2020 and December 7, 2020, we completed the semi-annual re-determinations of our revolving credit facility resulting in a reduction of the borrowing base from $300.0 million to $225.0 million and further to $215.0 million, with $200 million readily available and $15 million subject to approval by majority lenders until June 29, 2021 and $20 million plus 50% of outstanding amounts owing under certain advance payment agreements starting June 30, 2021 and ending October 1, 2021. We intentionally apply all excess cash to the facility and minimize cash on the balance to reduce borrowing costs. We can borrow under the facility by providing the lenders with two days notice. Availability under the revolving credit facility is determined by the reserves-based borrowing determined by the lenders. At December 31, 2020, we had $190.0 million drawn under the revolving credit facility. As of February 19, 2021, outstanding borrowings under our credit facility remained at $190.0 million.
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We have also obtained a relief from compliance with certain financial covenants until October 1, 2021 ("the covenant relief period"), permitting the ratio of total debt to Covenant EBITDAX ("EBITDAX") to be greater than 4.0 to 1.0, Senior Secured Debt to EBITDAX ratio must not exceed 2.5 to 1.0, and EBITDAX to interest expense ratio for the trailing four quarter periods measured as of the last day of the fiscal quarters ending (i) December 31, 2020 and March 31, 2021, must be at least 1.5 to 1.0 (ii) June 30, 2021 and September 30, 2021 must be at least 2.0 to 1.0, and be at least 2.5 to 1.0 thereafter. We are required to comply with various covenants, which as disclosed above, have been modified in response to the current market conditions and the COVID-19 pandemic. As of December 31, 2020, we were in compliance with all applicable covenants under the revolving credit facility.
In addition to the covenant relief, the amendment to the credit agreement in connection with the semi-annual re-determination also amended the interest rate to either, at the borrower’s option, LIBOR plus a spread ranging from 2.90% to 4.90%, or base rate plus a spread ranging from 1.90% to 3.90%, with such spread in each case dependent upon our Senior Secured Leverage Ratio (as defined in the credit agreement), provided that during the covenant relief period the spread is increased by 125 basis points, (i) provided for a borrowing condition that we shall not have cash and cash equivalents (other than Excluded Cash, as defined in the credit agreement) in excess of $15.0 million, (ii) added certain mandatory prepayments, including for cash balances in excess of $15.0 million and (iii) amended and added certain negative covenants, including, without limitation, certain additional limitations on occurrence of indebtedness, liens and investments, the making of restricted payments, prepayments of indebtedness, and acquisitions and mergers.
After the expiration of covenant relief period, we must maintain compliance with the following financial covenants: limitations on Company's ratio of debt to EBITDAX to a maximum of 4.0 to 1.0; limitations on Company's ratio of Senior Secured Debt to EBITDAX to a maximum of 3.0 to 1.0; and the maintenance of a ratio of EBITDAX to interest expense of at least 2.5 to 1.0. If we fail to comply with these financial covenants, it would result in a default under the terms of the credit agreement, which could result in an acceleration of repayment of all indebtedness under our revolving credit facility. Under the terms of the credit facility, we are limited in our ability to pay any dividends to our shareholders without bank approval.
At December 31, 2020, we had $300.0 million of 7.75% Senior Notes due 2027 (the “7.75% Senior Notes”) and $300.0 million of 6.25% Senior Notes due 2025 (the “6.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Senior Notes”) The Senior Notes are fully and unconditionally guaranteed by the Company and certain subsidiaries of the Company that guarantee its revolving credit facility.
The 7.75% Senior Notes bear interest at a rate of 7.75% per year, payable semi-annually in arrears on May 23 and November 23 of each year, beginning on November 23, 2019. The 7.75% Senior Notes will mature on May 23, 2027, unless earlier redeemed or repurchased.

The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 6.25% Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.

An event of default under the revolving credit facility would result in a default under the indentures governing the Senior Notes, which could allow the note holders to require us to repurchase all of the outstanding Senior Notes.

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

At December 31, 2020, 97% of our cash and cash equivalents were held by subsidiaries outside of Canada and the United States.

Derivative Positions

At December 31, 2020, we had outstanding commodity price derivative positions as follows:

Period and Type of InstrumentVolume,
bopd
ReferenceSold Put ($/bbl, Weighted Average)Purchased Put ($/bbl, Weighted Average)Sold Call
($/bbl, Weighted Average)
Premium
($/bbl, Weighted Average)
Three-way Collars: January 1, to June 30, 202114,000 ICE Brent36.43 45.14 51.45 0.21 
Collars: January 1, to June 30, 20211,000 ICE Brentn/a 45.00 50.40 n/a
Swaptions: July 1, to December 31, 20213,000 ICE Brentn/an/a56.75 n/a

Subsequent to December 31, 2020 , we entered into commodity price and foreign currency derivative positions as follows:

Period and Type of InstrumentVolume,
bopd
ReferenceSold Put ($/bbl, Weighted Average)Purchased Put ($/bbl, Weighted Average)Sold Call
($/bbl, Weighted Average)