EDGAR 10-K Filing

Company CIK: 1273441
Filing Year: 2021
Filename: 1273441_10-K_2021_0001273441-21-000007.json

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ITEM 1. BUSINESS
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,
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.
Oil and Gas Properties - Colombia and Ecuador
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.
Exploration Blocks & Commitments
The following table provides a summary of our exploration commitments for certain blocks as of December 31, 2020:
Basin Block Current Phase Remaining Commitments, Current Phase
Colombia
Putumayo Alea
1848-A 3 & 4 one exploration well
Putumayo Alea
1947-C 2 one exploration well
Putumayo PUT-1 2* two exploration wells
Putumayo PUT-2 2* three exploration wells
Putumayo PUT-4 1 one exploration well
Putumayo PUT-7 2 two exploration wells
Putumayo PUT-10 1* 73 km 2D seismic, two exploration wells
Putumayo PUT-25 1 one exploration well
Putumayo PUT-31 1 202 km 2D seismic, one exploration well
Llanos LLA-1 1* 97.5 km2 3D seismic, one exploration well
Llanos LLA-5 1* 133 km2 3D seismic, one exploration well
Llanos LLA-22 1 & 2* 85 km2 3D seismic, one exploration well
Llanos LLA-70 1* 163 km2 3D seismic, one exploration well
Llanos LLA-85 1 50 km2 3D seismic, 451 km2 3D seismic reprocessing
MMV VMM-24 1 50 km2 3D seismic, 100 km 2D seismic reprocessing, 100 km aerogeophysics, 100 km2 remote sensing, 80 km2 surface geochemistry, one exploration well
Ecuador
Oriente Charapa 1 50 km 2D seismic, seven exploration wells
Oriente Chanangue 1 five exploration wells
Oriente Iguana 1 two 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
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.
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.
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:
Oil Natural Gas Oil and Natural Gas
Reserves Category (Mbbl) (MMcf) (MBOE)
Proved
Total proved developed reserves 38,660 633 38,766
Total proved undeveloped reserves 26,032 1,022 26,202
Total proved reserves 64,692 1,655 64,968
Probable (1)
Total probable developed reserves 16,818 96 16,834
Total probable undeveloped reserves 26,997 1,044 27,171
Total probable reserves 43,815 1,140 44,005
Possible (1)
Total possible developed reserves 14,145 205 14,179
Total possible undeveloped reserves 29,171 1,206 29,372
Total possible reserves 43,316 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.
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.
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 1,773,723 792,011 438,799 3,612,338 7,346,200
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
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.
2020 2019 2018
Gross Net Gross Net Gross Net
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
Productive 6.00 6.00 22.00 22.00 19.00 18.16
Dry - - 2.00 2.00 - -
In progress 1.00 1.00 1.00 1.00 4.00 4.00
Service
Water injectors 1.00 1.00 5.00 5.00 - -
Total Colombia 8.00 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
Gross Net
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
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
Gross Net Gross Net Gross Net
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
Total 312,302 219,913 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.
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
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.
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.

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ITEM 1A. RISK FACTORS
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;
•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.
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.
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
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
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
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
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.
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
Information About Our Executive Officers
Set forth below is information regarding our executive officers as of February 19, 2021.
Name Age Position
Gary S. Guidry 65 President and Chief Executive Officer, Director
Ryan Ellson 45 Chief Financial Officer and Executive Vice President, Finance
James Evans 55 Vice President, Corporate Services
Glen Mah 64 Vice President, Exploration Ecuador
Rodger Trimble 59 Vice President, Investor Relations
Lawrence West 64 Vice 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
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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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”).

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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
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
•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 % Change 2019
SEC Compliant Reserves, NAR (MMBOE)
Estimated proved oil and gas reserves 65 (4) 68
Estimated probable oil and gas reserves 44 (24) 58
Estimated possible oil and gas reserves 44 16 38
Average Consolidated Daily Volumes (BOPD)
Working interest ("WI") production before royalties 22,624 (35) 34,817
Royalties (2,552) (56) (5,802)
Production NAR 20,072 (31) 29,015
Decrease in inventory 91 (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 % Change 2019
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.
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) 2020 2019 2020 2019 2020
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 expenses 164,233 225,033 33,115 60,603 31,340
Interest expense 54,140 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 impairment 564,495 - 57,402 196 104,731
Goodwill impairment 102,581 - - - -
Non-cash lease expense 1,951 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 instruments 55,856 (49,488) (5,983) (44,323) (5,086)
Other non-cash loss 2,026 - - - 2,026
Stock-based compensation expense 1,216 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:
Year Ended December 31, Three Months Ended,
December 31, December 31, September 30,
(Thousands of U.S. Dollars) 2020 2019 2020 2019 2020
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 expenses 164,233 225,033 33,115 60,603 31,340
Asset impairment 564,495 - 57,402 - 104,731
Goodwill impairment 102,581 - - - -
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 costs 3,625 3,376 851 802 838
Non-cash lease expense 1,951 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 loss 2,026 - - - 2,026
Financial instruments loss (gain) 50,982 (46,215) (887) (43,325) (713)
Cash settlement of financial instruments 4,874 (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 % Change 2019
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
COVID-19 related costs 2,679 100 -
DD&A expenses 164,233 (27) 225,033
Asset impairment 564,495 100 -
Goodwill Impairment 102,581 100 -
G&A expenses before stock-based compensation 22,506 (32) 33,300
G&A stock-based compensation expense 1,216 (15) 1,430
Severance expenses 1,628 (8) 1,771
Foreign exchange loss 4,184 567 627
Financial instruments loss (gain) 50,982 210 (46,215)
Interest expense 54,140 25 43,268
968,644 274 259,214
Other loss (469) (96) (12,886)
Interest income 345 (50) 696
(Loss) income before income taxes (853,361) (989) 95,975
Current income tax expense 754 (96) 17,058
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, BOPD 20,163 (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 expenses 15.16 (12) 17.23
Transportation expenses 1.43 (26) 1.92
Operating netback (1)
15.64 (55) 34.53
COVID-19 related costs 0.36 100 -
DD&A expenses 22.25 5 21.16
Asset impairment 76.49 100 -
Goodwill Impairment 13.90 100 -
G&A expenses before stock-based compensation 3.05 (3) 3.13
G&A stock-based compensation expense 0.16 23 0.13
Severance expenses 0.22 29 0.17
Foreign exchange loss 0.57 850 0.06
Financial instruments loss (gain) 6.91 259 (4.35)
Interest expense 7.34 80 4.07
131.25 439 24.37
Other loss (0.06) 95 (1.21)
Interest income 0.05 (29) 0.07
(Loss) income before income taxes (115.62) (1,382) 9.02
Current income tax expense 0.10 (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) 2020 2019
WI production before royalties 22,624 34,817
Royalties (2,552) (5,802)
Production NAR 20,072 29,015
Decrease in inventory 91 125
Sales 20,163 29,140
Royalties, % of working interest production before royalties 11 % 17 %
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.
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) 2020 2019
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:
Year Ended December 31,
2020 2019
Volume transported through pipelines 4 % 1 %
Volume sold at wellhead 48 % 51 %
Volume transported via truck to pipelines 48 % 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.
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) 2020 2019
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 expense 0.49 0.85
Average realized price net of transportation expenses for the year $ 30.80 $ 51.76
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.
Operating Netbacks
Year Ended December 31,
Consolidated 2020 2019
(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 price 32.23 53.68
Transportation expenses (1.43) (1.92)
Average realized price net of transportation expenses 30.80 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.
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,
2020 2019
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) 2020 2019
Impairment of oil and gas properties $ 560,344 $ -
Impairment of inventory 4,151 -
$ 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
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 % change 2019
G&A expenses before stock-based compensation $ 22,506 (32) $ 33,300
G&A stock-based compensation 1,216 (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 compensation 0.16 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.
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,
2020 2019
Change in the Colombian peso against the U.S. dollar weakened by weakened by
5 % 1 %
Change in the Canadian dollar against the U.S. dollar strengthened by strengthened by
2 % 5 %
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:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Commodity price derivative (gain) loss $ (220) $ 3,642
Foreign currency derivative loss 3,155 27
Investment loss (gain) 46,883 (49,884)
Financial instruments loss 1,164 -
$ 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) 2020 2019
(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 rate 9 % 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 assets 902,519
Total tax pools and credits $ 1,154,551
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 volumes 7,617 (38,147) (174,811)
Prices 4,034 (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 costs 106 (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 taxes 443 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 impairment 47,329 (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 payments 159 139 (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 settlements 897 (38,340) (105,344)
Unrealized foreign exchange 20,144 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.
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
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.
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)
Development 7.0
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.
Liquidity and Capital Resources
As at December 31,
(Thousands of U.S. Dollars) 2020 % Change 2019
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.
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 $300.0 million of 6.25% Senior Notes due 2025 (the “6.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Senior Notes”) The Senior Notes are fully and unconditionally guaranteed by the Company and certain subsidiaries of the Company that guarantee its revolving credit facility.
The 7.75% Senior Notes bear interest at a rate of 7.75% per year, payable semi-annually in arrears on May 23 and November 23 of each year, beginning on November 23, 2019. The 7.75% Senior Notes will mature on May 23, 2027, unless earlier redeemed or repurchased.
The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 6.25% Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.
An event of default under the revolving credit facility would result in a default under the indentures governing the Senior Notes, which could allow the note holders to require us to repurchase all of the outstanding Senior Notes.
Cash and Cash Equivalents Held Outside of Canada and the United States
At December 31, 2020, 97% of our cash and cash equivalents were held by subsidiaries outside of Canada and the United States.
Derivative Positions
At December 31, 2020, we had outstanding commodity price derivative positions as follows:
Period and Type of Instrument Volume,
bopd Reference Sold Put ($/bbl, Weighted Average) Purchased Put ($/bbl, Weighted Average) Sold Call
($/bbl, Weighted Average) Premium
($/bbl, Weighted Average)
Three-way Collars: January 1, to June 30, 2021 14,000 ICE Brent 36.43 45.14 51.45 0.21
Collars: January 1, to June 30, 2021 1,000 ICE Brent n/a 45.00 50.40 n/a
Swaptions: July 1, to December 31, 2021 3,000 ICE Brent n/a n/a 56.75 n/a
Subsequent to December 31, 2020 , we entered into commodity price and foreign currency derivative positions as follows:
Period and Type of Instrument Volume,
bopd Reference Sold Put ($/bbl, Weighted Average) Purchased Put ($/bbl, Weighted Average) Sold Call
($/bbl, Weighted Average) Premium
($/bbl, Weighted Average)
Three-way Collars: July 1, to December 31, 2021 4,000 ICE Brent 45.00 55.00 68.00 n/a
A collar limits the range of possible positive and negative returns and provides us downside protection at a lower cost compared to a swap.
Period and Type of Instrument Amount Hedged
(Millions of COP) U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)
Reference Floor Price
(COP, Weighted Average) Cap Price (COP, Weighted Average)
Collars: March 1, to December 31, 2021 10,000 3,051 COP 3,500 3,630
(1) At December 31, 2020 foreign exchange rate.
Cash Flows
The following table presents our sources and uses of cash and cash equivalents for the periods presented:
Year Ended December 31,
2020 2019
Sources of Cash and Cash Equivalents:
Net (loss) income $ (777,967) $ 38,690
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses 164,233 225,033
Asset impairment 564,495 -
Goodwill Impairment 102,581 -
Deferred tax (recovery) expense (76,148) 40,227
Stock-based compensation expense 1,216 1,430
Amortization of debt issuance costs 3,625 3,376
Unrealized foreign exchange loss 5,271 1,803
Other non-cash loss 2,026 -
Financial instruments loss (gain) 50,982 (46,215)
Non-cash lease expenses 1,951 1,806
Lease payments (1,926) (1,969)
Cash settlement of financial instruments 4,874 (3,273)
Loss on redemption of Convertible Notes - 11,501
Funds flow from operations (1)
45,213 272,409
Changes in non-cash operating working capital 36,062 -
Proceeds from issuance of Senior Notes, net of issuance costs - 289,271
Proceeds from other debt, net of issuance costs 88,332 342,575
169,607 904,255
Uses of Cash and Cash Equivalents:
Additions to property, plant and equipment - property acquisitions - (77,772)
Additions to property, plant and equipment (96,281) (379,314)
Repayment of debt (17,000) (349,219)
Lease payments (879) -
Changes in non-cash operating working capital - (93,874)
Changes in non-cash investing working capital (48,642) (7,851)
Cash settlement of asset retirement obligation (201) (870)
Repurchase of shares of Common Stock - (37,561)
Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents (156) (1,027)
(163,159) (947,488)
Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents $ 6,448 $ (43,233)
(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.
Off-Balance Sheet Arrangements
As at December 31, 2020 and 2019, we had no off-balance sheet arrangements.
Contractual Obligations
The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancelable terms in excess of one year as of December 31, 2020:
(Thousands of U.S. Dollars) Total 2021 2022-2023
2024-2025
2026 and beyond
Revolving credit facility $ 190,000 $ - $ 190,000 $ - $ -
6.25% Senior Notes
300,000 - - 300,000 -
7.75% Senior Notes
300,000 - - - 300,000
Total long-term debt 790,000 - 190,000 300,000 300,000
Interest payments (1)
245,965 52,729 93,209 67,542 32,485
Operating leases 4,910 2,330 2,580 - -
Finance leases 4,725 3,197 1,501 27 -
Software and Telecommunication 900 300 600 - -
Total $ 1,046,500 $ 58,556 $ 287,890 $ 367,569 $ 332,485
(1) Interest payments were calculated by assuming that our revolving credit facility outstanding balance at December 31, 2020 of $190.0 million will be outstanding through the November 2022 maturity date and our 6.25% Senior Notes and 7.75% Senior Notes will be held until their maturity dates of February 2025 and May 2027, respectively. Actual results will differ from these estimates and assumptions.
At December 31, 2020, we had provided promissory notes totaling $100.6 million (2019 - $120.6 million) to support letters of credit or surety bonds relating to work commitment guarantees contained in exploration contracts and other capital or operating requirements. These unsecured letters of credit do not utilize our revolving credit facility capacity because they are backed by local Colombian banks and Export Development Canada.
The above table does not reflect estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties and other long-term liabilities, as we cannot determine with accuracy the timing of such payments. Information regarding our asset retirement obligation can be found in Note 10 to the Consolidated Financial Statements, Asset Retirement Obligation, in Item 8 “Financial Statements and Supplementary Data”.
As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost and associated penalties may be payable.
Critical Accounting Policies and Estimates
The preparation of financial statements under GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as well as the revenues and expenses reported and disclosure of contingent liabilities. Changes in these estimates related to judgments and assumptions will occur as a result of changes in facts and circumstances or discovery of new information, and, accordingly, actual results could differ from amounts estimated.
On a regular basis we evaluate our estimates, judgments and assumptions. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.
Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material. The areas of accounting and the associated critical estimates and assumptions made are discussed below.
Full Cost Method of Accounting, Proved Reserves, DD&A and Impairment of Oil and Gas Properties
We follow the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note 2 to the Consolidated Financial Statements, Significant Accounting Policies, in Item 8 “Financial Statements and Supplementary Data”. Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of properties are capitalized, including internal costs directly attributable to these activities. The
sum of net capitalized costs, including estimated asset retirement obligations ("ARO"), and estimated future development costs to be incurred in developing proved reserves are depleted using the unit-of-production method.
Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation. The ceiling test limits pooled costs to the aggregate of the discounted estimated after-tax future net revenues from proved oil and gas properties, plus the lower of cost or estimated fair value of unproved properties less any associated tax effects.
If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. Any such write-down will reduce earnings in the period of occurrence and result in lower DD&A expenses in future periods. The ceiling limitation is imposed separately for each country in which we have oil and gas properties. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
Our estimates of proved oil and gas reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the amount and timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.
We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are evaluated at least annually by independent qualified reserves consultants.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that a 10% discount factor be used and future net revenues are calculated using prices that represent the average of the first day of each month price for the 12-month period. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but reflect adjustments for gravity, quality, local conditions, gathering and transportation fees and distance from market. Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2020, ceiling tests were based on wellhead prices per bbl as of the first day of each month within that twelve month period.
Because the ceiling test calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. Historical oil and gas prices for any particular 12-month period can be either higher or lower than our price forecast. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Our Reserves Committee oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reserves consultants to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence.
We assessed our oil and gas properties for impairment as at December 31, 2020, and recorded ceiling test impairment losses of
$560.3 million related to lower oil prices. For the year ended December 31, 2019, we had no ceiling test impairment losses. We used an average Brent price of $43.43 per bbl less corresponding differentials for the purposes of the December 31, 2020 ceiling test calculations (2019 - $64.20).
It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed U.S. GAAP ceiling test calculation. These factors include,
but are not limited to, future commodity pricing, royalty rates in different pricing environments, operating costs and negotiated savings, foreign exchange rates, capital expenditures timing and negotiated savings, production and its impact on depletion and cost base, upward or downward reserve revisions as a result of ongoing exploration and development activity, and tax attributes.
Unproved Properties
Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. Unproved properties, the costs of which are individually significant, are assessed individually by considering seismic data, plans or requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans and political, economic and market conditions. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, seismic evaluations, the assignment of proved reserves, availability of capital and other factors. For countries where a reserve base has not yet been established, the impairment is charged to earnings.
Asset Retirement Obligations
We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate.
We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, inflation factors, credit-adjusted risk-free discount rates and changes in legal, regulatory, environmental and political environments. Because costs typically extend many years into the future, estimating future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.
It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results.
Equity Method Investment
During December 2017, we acquired an investment in common shares of PetroTal Corp. ("PetroTal") in connection with the sale of our Peru business unit. At December 31, 2020, this investment represented approximately 30% of PetroTal's issued and outstanding common shares. We determined that we did not have a controlling financial interest in PetroTal, but could exert significant influence over PetroTal's operating and financial policies as a result of our ownership interest in PetroTal and the right to nominate two directors to PetroTal's board of directors. Accordingly, we accounted for our investment in the common shares of PetroTal as an equity method investment, but elected the fair value option for this investment. On January 21, 2021 we sold 44% percent of our interest in PetroTal for cash proceeds of $14.8 million.
The fair value of the investment was estimated using quoted market prices in active markets. Information regarding the valuation of the investment can be found in Note 15 to the Consolidated Financial Statements, Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk in Item 8 “Financial Statements and Supplementary Data”, which information is incorporated by reference here.
Goodwill
Goodwill represented the excess of the aggregate of the consideration transferred over net identifiable assets acquired and liabilities assumed. The goodwill that was recorded on our balance sheet related entirely to our Colombia reporting unit.
At each reporting date, we assessed qualitative factors to determine whether it was more likely than not that the fair value of the reporting unit was less than its carrying amount and whether it was necessary to perform the goodwill impairment test. Changes in our future cash flows, operating results, growth rates, capital expenditures, cost of capital, discount rates, stock price or related market capitalization, could affect the results of our annual goodwill assessment and, accordingly, led to goodwill impairment charges. The goodwill impairment test required a comparison of the fair value of the reporting unit to its net book value. We performed step 1 of the goodwill impairment test as at the end of the first quarter of 2020, which resulted in a full write-down of goodwill. The most significant judgments involved in estimating the fair value of our reporting unit related to the valuation of our property and equipment.
Leases
At inception of a contract, we assess whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, we allocate the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. We recognize a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.
The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, our incremental borrowing rate. Generally, we use our incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.
We have applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether we are reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.
Revenue from Contracts with Customers
Our revenue relates to oil sales in Colombia. We recognize revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents our share and is recorded net of royalty payments to governments and other mineral interest owners.
We evaluate our arrangement with third parties and partners to determine if we act as a principal or an agent. In making this evaluation, our management considers if we obtain control of the product delivered, which is indicated by us having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If we act in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by us from the transaction.
Tariffs, tolls and fees charged to other entities for use of pipelines owned by us are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements.
In the comparative period, revenue from the production of oil and natural gas was recognized when the customer took title and assumed the risks and rewards of ownership, prices were fixed or determinable, the sale was evidenced by a contract and collection of the revenue was reasonably assured.
When determining if we acted as a principal or as an agent in transactions, management determines if we obtain control of the product. As part of this assessment, management considers detailed criteria for revenue recognition set out in ASC 606.
Allowance for credit losses
At each reporting date, we assess the expected lifetime credit losses on initial recognition of trade accounts receivable. Credit risk is assessed based on the number of days the receivable has been outstanding and the internal credit assessment of the customer. The expected loss rates are based on payment profiles over a period of 36 months prior to the period-end and the corresponding historical credit losses experienced within this period. Historical loss rates are adjusted to reflect current and forward looking economic factors of the country where we sell oil affecting the ability of the customers to settle the receivables. Trade receivables are written off when there is no reasonable expectation of recovery.
Income Taxes
We follow the liability method of accounting for income taxes whereby we recognize deferred income tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.
To assess the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.
Our effective tax rate is based on pre-tax income and the tax rates applicable to that income in the various jurisdictions in which we operate. An estimated effective tax rate for the year is applied to our quarterly operating results. In the event that there is a significant unusual or discrete item recognized, or expected to be recognized, in our quarterly operating results, the tax attributable to that item would be separately calculated and recorded at the same time as the unusual or discrete item. We consider the resolution of prior-year tax matters to be such items. Significant judgment is required in determining our effective tax rate and in evaluating our tax positions. We establish reserves when it is more likely than not that we will not realize the full tax benefit of the position. We adjust these reserves in light of changing facts and circumstances.
We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts.
Legal and Other Contingencies
A provision for legal and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal and other contingencies and periodically determines when we should record losses for these items based on information available to us.
Stock-Based Compensation
Our stock-based compensation cost is measured based on the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes simulation stock option-pricing model and/or observable share prices. These estimates depend on certain assumptions, including volatility, risk-free interest rate, the term of the awards, the forfeiture rate and performance factors, which, by their nature, are subject to measurement uncertainty. We use historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of our shares. The risk-free
rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.
Risks and Measurement uncertainty
In March 2020, 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 physical 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 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 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. 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. In the near term, matters in these financial statements that are most subject to be impacted by this volatile period are our assessment of liquidity and access to capital, the carrying value of long-lived assets and the valuation of the deferred tax assets.
Recently Adopted Accounting Pronouncements
Financial Instruments - Credit Losses (ASC 326)
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of reasonable and supportable information to support credit loss estimates. In December 2019, the FASB issued ASU 2019-10, "Financial Instruments - Credit Losses, Derivatives and Hedging and Leases", which is codification improvement of ASU 2016-13. We adopted this ASU on January 1, 2020, the adoption of which had no impact on our consolidated balance sheet, results of operations or cash flows.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Gran Tierra Energy Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Gran Tierra Energy Inc. (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, shareholders’ equity and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 24, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the Audit Committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Realizability of the deferred income tax asset.
As discussed in Note 13 to the consolidated financial statements, as of December 31, 2020, the Company had recognized a deferred income tax asset of $57.3 million. The Company estimated that there was a greater than 50 percent likelihood that the deferred income tax asset will be realized. The determination of the deferred income tax asset involves a number of estimates, including the future cash flows associated with the estimated proved oil and gas reserves (“proved reserves”). The estimation of the proved reserves involves the expertise of independent reservoir engineering specialists, who take into consideration assumptions related to its forecasted production, forecasted operating, royalty and capital cost assumptions and forecasted oil prices (“reserve assumptions”). The Company engages independent reservoir engineering specialists to estimate the proved reserves.
We identified the evaluation of the realizability of the deferred income tax asset as a critical audit matter. Changes in reserve assumptions could have had a significant impact on the determination of the Company’s ability to realize the deferred income tax asset and the amount of a valuation allowance, if any. A high degree of auditor judgment was required in evaluating the reserve assumptions used to estimate the proved reserves, which was an input to derive the deferred income tax asset. Additionally, the nature and extent of audit effort associated with this estimate required specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter, including controls over the estimation of the proved reserves and the related reserve assumptions. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists engaged by the Company, who estimated the proved reserves. We evaluated the methodology used by independent reservoir engineering specialists to estimate the proved reserves for compliance with regulatory standards. We compared the 2020 actual production, operating, royalty and capital costs to those estimates used in the prior year’s estimate of the proved reserves to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the proved reserves by comparing them to those published by other reserve engineering firms. We assessed the estimates of forecasted production and forecasted operating, royalty and capital cost assumptions used in the proved reserves by comparing them to historical results. We involved Canadian and Colombian income tax professionals with specialized skills and knowledge who assisted in evaluating the application of relevant tax laws and regulations used in the determination of the recognized deferred tax asset.
Impact of estimated proved oil reserves on the calculations of depletion expense and the ceiling test related to oil and gas properties
As discussed in Note 2 to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-of-production method on a country-by-country basis. Under such method, capitalized costs associated with Colombia are depleted over the estimated proved oil and gas reserves associated with Colombia. As discussed in Note 5 to the consolidated financial statements, for the year ended December 31, 2020, the Company recorded depletion and depreciation expense of $160.8 million. Additionally, as discussed in Note 2 and 6 to the consolidated financial statements, the Company performs a ceiling test calculation each quarter and for the year ended December 31, 2020 the Company recorded ceiling test impairments of $560.3 million. In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved reserves discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to net income or loss. The estimation of proved reserves, which are used in the calculations of depletion and the ceiling test, involves the expertise of independent reservoir engineering specialists, who take into consideration reserve assumptions. The Company engages independent reservoir engineering specialists to estimate the proved reserves.
We identified the assessment of the impact of estimated proved reserves on the calculations of depletion expense and the ceiling test related to oil and gas properties as a critical audit matter. Changes in reserve assumptions could have had a significant impact on the calculations of depletion expense and the ceiling tests. A high degree of auditor judgment was required in evaluating the proved reserves, and related reserve assumptions, which were an input to the calculations of depletion expense and the ceiling test.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter, including controls over the calculation of depletion expense and the ceiling test and controls over the estimation of the proved reserves, including the reserve assumptions. We assessed the calculations of depletion expense and the ceiling test for compliance with regulatory standards. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists engaged by the Company, who estimated the proved reserves. We evaluated the methodology used by the independent reservoir engineering specialists to estimate the proved reserves for compliance with regulatory standards. We compared the Company’s 2020 actual production, operating, royalty and capital costs to those estimates used in the prior year’s estimate of the proved reserves to assess the Company’s ability to accurately forecast. We assessed the estimates of forecasted production and forecasted operating, royalty and capital cost assumptions used in the estimate of the proved reserves by comparing them to historical results.
We have served as the Company’s auditor since 2018.
/s/ KPMG LLP
Chartered Professional Accountants
Calgary, Canada
February 24, 2021
Gran Tierra Energy Inc.
Consolidated Statements of Operations
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
Year Ended December 31,
2020 2019
OIL SALES (NOTE 11)
$ 237,838 $ 570,983
EXPENSES
Operating 111,888 183,204
Transportation 10,543 20,400
COVID-19 related costs (Note 12)
2,679 -
Depletion, depreciation and accretion (Note 5)
164,233 225,033
Goodwill impairment (Note 6)
102,581 -
Asset impairment (Note 6)
564,495 -
General and administrative 23,722 34,730
Severance 1,628 1,771
Foreign exchange loss
4,184 627
Financial instruments loss (gain) (Note 15)
50,982 (46,215)
Interest expense (Note 8)
54,140 43,268
TOTAL EXPENSES 1,091,075 462,818
OTHER LOSS
(469) (12,886)
INTEREST INCOME 345 696
(LOSS) INCOME BEFORE INCOME TAXES (853,361) 95,975
INCOME TAX EXPENSE (RECOVERY)
Current (Note 13)
754 17,058
Deferred (Note 13)
(76,148) 40,227
(75,394) 57,285
NET AND COMPREHENSIVE (LOSS) INCOME $ (777,967) $ 38,690
NET (LOSS) INCOME PER SHARE
-BASIC AND DILUTED
$ (2.12) $ 0.10
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC (Note 9)
366,981,556 376,495,306
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED (Note 9)
366,981,556 376,507,812
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Balance Sheets
(Thousands of U.S. Dollars, Except Share and Per Share Amounts)
As at December 31,
2020 2019
ASSETS
Current Assets
Cash and cash equivalents $ 13,687 $ 8,301
Restricted cash and cash equivalents (Note 10)
427 516
Accounts receivable (Note 3)
8,044 36,291
Investment (Note 15)
48,323 94,741
Taxes receivable (Note 4)
49,962 135,838
Other current assets 13,459 15,001
Total Current Assets 133,902 290,688
Oil and Gas Properties (using the full cost method of accounting)
Proved 797,355 1,258,934
Unproved 161,763 310,809
Total Oil and Gas Properties 959,118 1,569,743
Other capital assets 5,364 7,650
Total Property, Plant and Equipment (Note 5)
964,482 1,577,393
Other Long-Term Assets
Taxes receivable (Note 4)
42,635 25,869
Deferred tax assets (Note 13)
57,318 44,003
Other long-term assets 3,425 4,130
Goodwill (Note 6)
- 102,581
Total Other Long-Term Assets 103,378 176,583
Total Assets $ 1,201,762 $ 2,044,664
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities (Note 7)
$ 100,784 $ 195,513
Derivatives (Note 15)
12,050 775
Taxes payable 37 -
Equity compensation award liability (Note 9 and 15)
805 3,053
Total Current Liabilities 113,676 199,341
Long-Term Liabilities
Long-term debt (Note 8)
774,770 700,459
Deferred tax liabilities (Note 13)
- 59,762
Asset retirement obligation (Note 10)
48,214 43,419
Equity compensation award liability (Note 9 and 15)
3,955 4,806
Other long-term liabilities 4,113 4,267
Total Long-Term Liabilities 831,052 812,713
Commitments and Contingencies (Note 14)
Shareholders’ Equity
Common Stock (Note 9) (366,981,556 and 366,981,556 shares of Common Stock, par value $0.001 per share, issued and outstanding as at December 31, 2020 and December 31, 2019, respectively)
10,270 10,270
Additional paid in capital 1,285,018 1,282,627
Deficit (1,038,254) (260,287)
Total Shareholders’ Equity 257,034 1,032,610
Total Liabilities and Shareholders’ Equity $ 1,201,762 $ 2,044,664
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Statements of Cash Flows
(Thousands of U.S. Dollars)
Year Ended December 31,
2020 2019
Operating Activities
Net (loss) income $ (777,967) $ 38,690
Adjustments to reconcile net (loss) income to net cash
provided by operating activities:
Depletion, depreciation and accretion (Note 5)
164,233 225,033
Goodwill Impairment (Note 6)
102,581 -
Asset impairment (Note 6)
564,495 -
Deferred tax (recovery) expense (Note 13)
(76,148) 40,227
Stock-based compensation (Note 9)
1,216 1,430
Amortization of debt issuance costs (Note 8)
3,625 3,376
Non-cash lease expenses 1,951 1,806
Lease payments (1,926) (1,969)
Unrealized foreign exchange loss 5,271 1,803
Financial instruments loss (gain) (Note 15)
50,982 (46,215)
Cash settlement of financial instruments 4,874 (3,273)
Cash settlement of asset retirement obligation (Note 10)
(201) (870)
Other non-cash loss 2,026 -
Loss on redemption of Convertible Notes - 11,501
Net change in assets and liabilities from operating activities (Note 16)
36,062 (93,874)
Net cash provided by operating activities 81,074 177,665
Investing Activities
Additions to property, plant and equipment (Note 5)
(96,281) (379,314)
Property acquisitions (Note 5)
- (77,772)
Changes in non-cash investing working capital (48,642) (7,851)
Net cash used in investing activities (144,923) (464,937)
Financing Activities
Proceeds from issuance of Senior Notes, net of issuance costs (Note 8)
- 289,271
Proceeds from bank debt, net of issuance costs 88,332 342,575
Repayment of debt (17,000) (349,219)
Lease payments (879) -
Repurchase of shares of Common Stock (Note 9)
- (37,561)
Net cash provided by financing activities 70,453 245,066
Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents (156) (1,027)
Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents 6,448 (43,233)
Cash and cash equivalents and restricted cash and cash equivalents,
beginning of year (Note 16)
11,075 54,308
Cash and cash equivalents and restricted cash and cash equivalents,
end of year (Note 16)
$ 17,523 $ 11,075
Supplemental cash flow disclosures (Note 16)
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Consolidated Statements of Shareholders’ Equity
(Thousands of U.S. Dollars)
Year Ended December 31,
2020 2019
Share Capital
Balance, beginning of year $ 10,270 $ 10,290
Repurchase of Common Stock (Note 9)
- (20)
Balance, end of year 10,270 10,270
Additional Paid in Capital
Balance, beginning of year 1,282,627 1,318,048
Stock-based compensation (Note 9)
2,391 2,120
Repurchase of Common Stock (Note 9)
- (37,541)
Balance, end of year 1,285,018 1,282,627
Deficit
Balance, beginning of year (260,287) (298,588)
Net (loss) income (777,967) 38,690
Cumulative adjustment for accounting changes related to leases (Note 2)
- (389)
Balance, end of year (1,038,254) (260,287)
Total Shareholders’ Equity $ 257,034 $ 1,032,610
(See notes to the consolidated financial statements)
Gran Tierra Energy Inc.
Notes to the Consolidated Financial Statements
For the Years Ended December 31, 2020 and 2019
(Expressed in U.S. Dollars, unless otherwise indicated)
1. Description of Business
Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on international oil and natural gas exploration and production with assets currently in Colombia and Ecuador.
2. Significant Accounting Policies
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).
Significant accounting policies are:
Basis of Consolidation
These consolidated financial statements include the accounts of the Company and its controlled subsidiaries. All intercompany accounts and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows; depreciation, depletion, amortization (“DD&A”) and impairment; impairment assessments of goodwill; timing of transfers from oil and gas properties not subject to depletion to the depletable base; asset retirement obligations; determining the value of the consideration transferred and the net identifiable assets acquired and liabilities assumed in connection with business combinations and determining goodwill; assessments of the likely outcome of legal and other contingencies; income taxes; stock-based compensation; and determining the fair value of derivatives. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents
Restricted cash and cash equivalents comprises cash and cash equivalents pledged to secure letters of credit and to settle asset retirement obligations. Letters of credit currently secured by cash relate to work commitment guarantees contained in exploration contracts. Restrictions will lapse when work obligations are satisfied pursuant to the exploration contract or an asset retirement obligation is settled. Cash and claims to cash that are restricted as to withdrawal or use for other than current operations or are designated for expenditure in the acquisition or construction of long-term assets are excluded from the current asset classification. The long-term portion of restricted cash and cash equivalents is included in other long-term assets on the Company's balance sheet.
Allowance for Doubtful Accounts
At each reporting date, the Company assesses the expected lifetime credit losses on initial recognition of trade accounts receivable. Credit risk is assessed based on the number of days the receivable has been outstanding and the internal credit assessment of the customer. The expected loss rates are based on payment profiles over a period of 36 months prior to the period-end and the corresponding historical credit losses experienced within this period. Historical loss rates are adjusted to
reflect current and forward looking economic factors of the country where the Company sells oil that affect the ability of the customers to settle the receivables. Trade receivables are written off when there is no reasonable expectation of recovery.
Investment in PetroTal Corp.
During December 2017, the Company acquired an investment in common shares of PetroTal Corp. ("PetroTal") in connection with the sale of its Peru business unit. At December 31, 2020, this investment represented approximately 30% of PetroTal's issued and outstanding common shares. The Company determined that it did not have a controlling financial interest in PetroTal, but could exert significant influence over PetroTal's operating and financial policies as a result of its ownership interest in PetroTal and the right to nominate two directors to PetroTal's board of directors. Accordingly, Gran Tierra accounted for its investment in the common shares of PetroTal as an equity method investment, but elected the fair value option for this investment to reflect the value that market participants would use to value the investment. The fair value of the investment in PetroTal's common shares is recorded as "Investment" on the Company's consolidated balance sheet, and the change in fair value is recorded in the consolidated statements of operations as financial instruments gains or losses. As at December 31, 2020, we held 246,100,000 common shares of PetroTal and subsequent to December 31, 2020 we disposed of 109,006,250 common shares resulting in 137,093,750 common shares held (17% of all total outstanding shares).
Derivatives
The Company records derivative instruments on its balance sheet at fair value as either an asset or liability with changes in fair value recognized in the consolidated statements of operations as financial instruments gains or losses. While the Company utilizes derivative instruments to manage the price risk attributable to its expected oil production and foreign exchange risk, it has elected not to designate its derivative instruments as accounting hedges under the accounting guidance.
Inventory
Inventory consists of oil in tanks and third party pipelines and supplies and is valued at the lower of cost and net realizable value. The cost of inventory is determined using the weighted average method. Oil inventories include expenditures incurred to produce, upgrade and transport the product to the storage facilities and include operating, depletion and depreciation expenses and cash royalties.
Income Taxes
Income taxes are recognized using the liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statements carrying amounts of existing assets and liabilities and their respective tax base, and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. Valuation allowances are provided if, after considering available evidence, it is not more likely than not that some or all of the deferred tax assets will be realized.
The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The Company recognizes potential penalties and interest related to unrecognized tax benefits as a component of income tax expense.
Oil and Gas Properties
The Company uses the full cost method of accounting for its investment in oil and natural gas properties as defined by the Securities and Exchange Commission (“SEC”). Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Costs associated with production and general corporate activities; however, are expensed as incurred. Separate cost centers are maintained for each country in which the Company incurs costs.
The Company computes depletion of oil and natural gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Future development costs related to properties with proved reserves are also included in the amortization base for computation of depletion. The costs of unproved properties are excluded from the amortization base until the properties are evaluated. The cost of exploratory dry wells is transferred to proved
properties, and thus is subject to amortization, immediately upon determination that a well is dry in those countries where proved reserves exist.
The Company performs a ceiling test calculation each quarter in accordance with SEC Regulation S-X Rule 4-10. In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to net income or loss. Any such write-down will reduce earnings in the period of occurrence and results in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
The Company calculates future net cash flows by applying the unweighted average of prices in effect on the first day of the month for the preceding 12-month period, adjusted for location and quality differentials. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts.
Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the depletable base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. This evaluation considers, among other factors, seismic data, requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to depletion. For countries where a reserve base has not yet been established, the impairment is charged to earnings.
In exploration areas, related seismic costs are capitalized in unproved property and evaluated as part of the total capitalized costs associated with a property. Seismic costs related to development projects are recorded in proved properties and therefore subject to depletion as incurred.
Gains and losses on the sale or other disposition of oil and natural gas properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.
Asset Retirement Obligation
The Company records an estimated liability for future costs associated with the abandonment of its oil and gas properties including the costs of reclamation of drilling sites. The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to the related oil and gas properties. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets. The accretion of the asset retirement obligation and amortization of the asset retirement cost are included in DD&A. If estimated future costs of an asset retirement obligation change, an adjustment is recorded to both the asset retirement obligation and oil and gas properties. Revisions to the estimated asset retirement obligation can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Other Capital Assets
Other capital assets, including additions and replacements, are recorded at cost upon acquisition and include furniture, fixtures and leasehold improvement, computer equipment, automobiles and right-of-use assets for operating and finance leases. Depreciation for furniture and fixtures, computer equipment and automobiles is provided using the straight-line method over the useful life of the asset. Leasehold improvements and right-of-use assets for operating and finance leases are depreciated on a straight-line basis over the shorter of the estimated useful life and the term of the related lease. The cost of repairs and maintenance is charged to expense as incurred.
Goodwill
Goodwill represents the excess of the aggregate of the consideration transferred over the net identifiable assets acquired and liabilities assumed. The Company assesses qualitative factors annually, or more frequently if necessary, to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether it is necessary to perform the goodwill impairment test. The impairment test requires allocating goodwill and certain other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared with its net book value. An impairment loss is recognized if the estimated fair value of the reporting unit is less than its carrying amount, not exceeding the carrying amount of goodwill allocated to that reporting unit. Because quoted market prices are not available for the Company’s reporting unit, the fair value of the reporting unit is estimated based upon estimated future cash flows of the reporting unit. The goodwill relates entirely to Colombia. The Company performed step 1 of the goodwill impairment test for the year-ended December 31, 2020 which resulted in a full write-down of goodwill.
Leases
At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At inception of a contract that contains a lease component, the Company allocates the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, and subsequently at cost less any accumulated depreciation and impairment losses, and adjusted for certain remeasurements of the lease liability.
The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.
The Company has applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether the Company is reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.
All leases identified as part of the transition on January 1, 2019 relate to office leases. The transition resulted in the recognition of a right-of-use asset presented in other capital assets of $3.8 million at January 1, 2019, the recognition of lease liabilities of $4.2 million and a $0.4 million impact on retained earnings. When measuring the lease liabilities, the Company's incremental borrowing rate was used. At January 1, 2019 the rates applied ranged between 5.6% and 9.1%.
Revenue from Contracts with Customers
The Company's revenue relates to oil sales in Colombia. The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Payment terms are generally within three business days following delivery of an invoice to the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.
The Company evaluates its arrangement with third parties and partners to determine if the Company acts as a principal or an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in transaction, then the revenue is recognized on a net-basis, only reflecting the fee realized by the Company from the transaction.
Tariffs, tolls and fees charged to other entities for use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements. When determining if the Company acted as a principal or as an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers criteria for revenue recognition set out in ASC 606.
Stock-based Compensation
The Company records stock-based compensation expense in its consolidated financial statements measured at the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes-Merton or Monte Carlo simulation stock option-pricing models and/or observable share prices. For equity-settled stock-based compensation awards, fair values are determined at the grant date and the expense, net of estimated forfeitures, is recognized using the accelerated method over the requisite service period. An adjustment is made to compensation expense for any difference between the estimated forfeitures and the actual forfeitures. For cash-settled stock-based compensation awards, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities.
The Company uses historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of the Company’s shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.
Stock-based compensation expense is capitalized as part of oil and natural gas properties or expensed as part of general and administrative (“G&A”) or operating expenses, as appropriate.
Foreign Currency Translation
The functional currency of the Company, including its subsidiaries, is the United States dollar. Monetary items are translated into the reporting currency at the exchange rate in effect at the balance sheet date and non-monetary items are translated at historical exchange rates. Revenue and expense items are translated in a manner that produces substantially the same reporting currency amounts that would have resulted had the underlying transactions been translated on the dates they occurred.
DD&A expense on assets is translated at the historical exchange rates similar to the assets to which they relate. Gains and losses resulting from foreign currency transactions, which are transactions denominated in a currency other than the entity’s functional currency, are recognized in net income or loss.
Earnings (Loss) per Share
Basic earnings (loss) per share is calculated by dividing net income or loss attributable to common shareholders by the weighted average number of shares of Common Stock and exchangeable shares issued and outstanding during each period. Diluted net income or loss per share is calculated by adjusting the weighted average number of shares of Common Stock and exchangeable shares outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume weighted average trading price of shares of Common Stock during the period.
Recently Adopted Accounting Pronouncements
Financial Instruments - Credit Losses (ASC 326)
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses". This ASU replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires a broader range of reasonable and supportable information to support credit loss estimates. In December 2019, the FASB issued ASU 2019-10, "Financial Instruments - Credit Losses, Derivatives and Hedging and Leases", which is codification improvement of ASU 2016-13. The Company adopted this ASU on January 1, 2020, the adoption of which had no material impact on the Company's consolidated balance sheet, results of operations or cash flows.
Risks and Measurement Uncertainty
In March 2020, 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 the Company operates, enacted emergency measures to combat the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods and physical distancing, 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 success of these interventions is not currently determinable. The current challenging economic climate is having and may continue to have significant adverse impacts on the 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 (see Note 6);
•inability to comply with covenants and restrictions in debt agreements;
•inability to access financing sources;
•increased risk of non-performance by the Company’s customers and suppliers;
•interruptions in operations as the Company adjusts personnel to the dynamic environment; and
•inability to operate or delay in operations as a result COVID-19 restrictions in the countries in which the Company operates.
The unprecedented decline in oil prices has materially reduced the Company’s forecasted EBITDAX and the estimated value of its oil reserves. Based on current forecasted Brent pricing and production levels, which can change materially in very short time frames, the Company is forecasted to be in compliance with the amended financial covenants contained in the Company's 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 Company’s senior secured credit facility is based on the lenders determination of the borrowing base. The borrowing base is determined, by the lenders, based on the Company’s 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, the Company’s 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 the Company will continue to meet the terms of the credit facility or obtain further amendments or waivers if and when required. The Company also expects to be able to maintain the borrowing base at a level in excess of the amount borrowed. However, there can be no assurances that the Company’s 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 the Company is not 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. In the near term, matters in these financial statements that are most subject to be impacted by this volatile period are the Company's assessment of liquidity and access to capital, the carrying value of long-lived assets and the valuation of the deferred tax assets.
3. Accounts Receivable
As at December 31,
(Thousands of U.S. Dollars) 2020 2019
Trade $ 3,799 $ 24,890
Other 4,245 11,401
Total Accounts Receivable $ 8,044 $ 36,291
4. Taxes Receivable
The table below shows the break-down of taxes receivable which are comprised of value added tax ("VAT") and income tax receivables.
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Current
VAT Receivable $ 35,977 $ 92,777
Income Tax Receivable 13,985 43,061
$ 49,962 $ 135,838
Long-Term
VAT Receivable $ 28,485 $ 25,869
Income Tax Receivable 14,150 -
$ 42,635 $ 25,869
Total Taxes Receivable $ 92,597 $ 161,707
The following table shows the movement of VAT and income tax receivables for the past two years:
(Thousands of U.S. Dollars) VAT Receivable Income Tax Receivable Total Taxes Receivable
Balance, December 31, 2018
$ 72,497 $ 1,613 $ 74,110
Collected through sales contracts (18,197) - (18,197)
Taxes paid 65,114 58,494 123,608
Current tax expense - (17,058) (17,058)
Foreign exchange loss (768) 12 (756)
Balance, December 31, 2019
$ 118,646 $ 43,061 $ 161,707
Collected through direct government refunds (40,884) (26,471) (67,355)
Collected through sales contracts (46,326) - (46,326)
Taxes paid 43,719 14,648 58,367
Current tax expense - (754) (754)
Foreign exchange loss (10,693) (2,349) (13,042)
Balance, December 31, 2020
$ 64,462 $ 28,135 $ 92,597
5. Property, Plant and Equipment
As at December 31,
(Thousands of U.S. Dollars) 2020 2019
Oil and natural gas properties
Proved $ 4,106,768 $ 3,850,565
Unproved 161,763 310,809
4,268,531 4,161,374
Other (1)
32,135 30,255
4,300,666 4,191,629
Accumulated depletion, depreciation and impairment (3,336,184) (2,614,236)
$ 964,482 $ 1,577,393
(1) The "other" category includes $11.4 million right-of-use assets for operating and finance leases which had a net book value of $4.4 million as at December 31, 2020 (December 31, 2019 - $9.7 million which had a net book value of $5.7 million).
Depletion and depreciation expense on property, plant and equipment for the year ended December 31, 2020, was $160.8 million (2019 - $220.8 million). A portion of depletion and depreciation expense was recorded as oil inventory in each year.
2019 Acquisitions
On February 20, 2019, the Company acquired 36.2% working interest ("WI") in the Suroriente Block and a 100% WI of the Llanos-5 Block for cash consideration of $79.1 million and a promissory note of $1.5 million included in current accounts payable on the Company's consolidated balance sheet. The cost of the assets was allocated to proved properties using relative fair values.
(Thousands of U.S. Dollars) 2019
Cost of Asset Acquisition:
Cash $ 79,100
Promissory note 1,500
$ 80,600
Allocation of Consideration Paid:
Oil and gas properties
Proved $ 52,530
Unproved 44,768
97,298
Net working capital (including cash acquired of $5.3 million)
(16,698)
$ 80,600
Unproved Oil and Natural Gas Properties
At December 31, 2020, unproved oil and natural gas properties consist of exploration lands held in Colombia and Ecuador. Unproved oil and natural gas properties are being held for their exploration value and are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and as exploration warrants whether or not future areas will be developed. The Company expects that approximately 100% of costs not subject to depletion at December 31, 2020, will be transferred to the depletable base within the next five years.
The following is a summary of Gran Tierra’s oil and natural gas properties not subject to depletion as at December 31, 2020:
Costs Incurred in
(Thousands of U.S. Dollars) 2020 2019 Prior to 2019
Total
Acquisition costs - Colombia $ - $ 5,582 $ 32,558 $ 38,140
Exploration costs - Colombia 4,652 57,328 56,429 118,409
Exploration costs - Ecuador 2,006 3,208 - 5,214
$ 6,658 $ 66,118 $ 88,987 $ 161,763
6. Impairment
Asset Impairment
Asset impairment for the years ended December 31, 2020 and 2019, was as follows:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Impairment of oil and gas properties $ 560,344 $ -
Impairment of inventory 4,151 -
$ 564,495 $ -
(i)Oil and gas property impairment
For the year ended December 31, 2020, Gran Tierra recorded ceiling test impairment losses of $560.3 million as a result of lower oil prices. The Company follows the full cost method of accounting for its oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after-tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price for 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. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, Gran Tierra used an average Brent price of $43.43 per bbl for the purposes of the December 31, 2020 ceiling test calculations (December 31, 2019 - $64.20 per bbl). There was no ceiling test impairment for the year ended December 31, 2019. Gran Tierra's total proved oil and gas reserves decreased 4% from the prior year.
(ii)Inventory impairment
For the year ended December 31, 2020, the Company 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, the Company recorded $102.6 million of goodwill impairment relating to its Colombia business unit. The impairment was due to the carrying value of the unit exceeding its fair value as a result of the impact of lower forecasted commodity prices. The estimated fair value of the Colombia business 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. There was no goodwill impairment for the year ended December 31, 2019.
7. Accounts Payable and Accrued Liabilities
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Trade $ 70,450 $ 151,747
Royalties 1,570 5,758
Employee compensation 1,701 6,861
Other 27,063 31,147
$ 100,784 $ 195,513
8. Debt and Debt Issuance Costs
The Company's debt at December 31, 2020 and 2019, was as follows:
As at December 31,
(Thousands of U.S. Dollars) 2020 2019
6.25% Senior Notes
$ 300,000 $ 300,000
7.75% Senior Notes
300,000 300,000
Revolving credit facility 190,000 118,000
Unamortized debt issuance costs (18,124) (21,081)
Long-term lease obligation (1)
2,894 3,540
Long-term debt $ 774,770 $ 700,459
(1) The current portion of the lease obligation has been included in accounts payable and accrued liabilities on the Company's balance sheet and totaled $3.3 million as at December 31, 2020 (December 31, 2019 - $3.3 million).
Senior Notes
At December 31, 2020, the Company 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.
Before May 23, 2023, the Company may, at its option, redeem all or a portion of the 7.75% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a “make-whole” premium. Thereafter, the Company may redeem all or a portion of the 7.75% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2023 - 103.875%; 2024 - 101.938%; 2025 and thereafter - 100%.
The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 6.25% Senior Notes will mature on February 15, 2025, unless earlier redeemed or repurchased.
Before February 15, 2022, the Company may, at its option, redeem all or a portion of the 6.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 6.25% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption at the following redemption prices: 2022 - 103.125%; 2023 - 101.563%; 2024 and thereafter - 100%.
Credit Facility
At December 31, 2020, the Company had a revolving credit facility with a syndicate of lenders with a borrowing base of $215.0 million. Availability under the revolving credit facility is determined by the reserves-based borrowing base determined by the lenders. During the year, as part of semi-annual redeterminations, the borrowing base was reduced from $300.0 million to $225.0 million on June 1, 2020 and was further reduced to $215.0 million on December 7, 2020. The credit facility matures on November 10, 2022. The next re-determination of the borrowing base is due to occur no later than May 2021.
Management has 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. The Company is 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, the Company was in compliance with all applicable covenants in the revolving credit facility.
Availability for borrowing or issuance of letters of credit during covenant relief period and until June 29, 2021 was reduced by $15.0 million and starting from June 30, 2021 and until the end of covenant relief period by $20.0 million.
After the expiration of covenant relief period, the Company 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 the Company fails to comply with these financial covenants, and relief from compliance with the covenants was not obtained, 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 the Company's revolving credit facility.
Amounts drawn down under the revolving credit facility bear interest, at the Company's option, at the USD LIBOR rate plus a margin ranging from 2.90% to 4.90% (December 31, 2019 - 1.65% to 3.65%), or an alternate base rate plus a margin ranging from 1.90% to 3.90% (December 31, 2019 - 0.65% to 2.65%), in each case based on the borrowing base utilization percentage. The alternate base rate is currently the U.S. prime rate. Undrawn amounts under the revolving credit facility bear interest from 0.73% to 1.23% (December 31, 2019 - 0.41% to 0.91%) per annum, based on the average daily amount of unused commitments.
The Company’s revolving credit facility is guaranteed by and secured against the assets of certain of the Company’s subsidiaries (the "Credit Facility Group"). Under the terms of the credit facility, the Company is subject to certain restrictions on its ability to distribute funds to entities outside of the Credit Facility Group, including restrictions on the ability to pay dividends to shareholders of the Company.
Interest Expense
The following table presents total interest expense recognized in the accompanying consolidated statements of operations:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Contractual interest and other financing expenses $ 50,515 $ 39,892
Amortization of debt issuance costs 3,625 3,376
$ 54,140 $ 43,268
The Company incurred debt issuance costs in connection with the issuance of the Senior Notes and its revolving credit facility. As at December 31, 2020, the balance of unamortized debt issuance costs has been presented as a direct deduction against the carrying amount of debt and is being amortized to interest expense using the effective interest method over the term of the debt.
9. Share Capital
Shares of Common Stock
Balance, December 31, 2018
387,079,027
Shares repurchased and canceled (20,097,471)
Balance, December 31, 2019 and 2020
366,981,556
The Company’s authorized share capital consists of 595,000,000 shares of capital stock, of which 570,000,000 was designated as Common Stock, par value $0.001 per share and 25,000,000 as Preferred Stock, par value $0.001 per share.
Equity Compensation Awards
The Company has an equity compensation program in place for its executives, employees and directors. Executives and employees are given equity compensation grants that vest based on a recipient's continued employment and in the case of Performance Share Units (“PSUs”), the number of units that vest is dependent upon the achievement of certain key
performance measures. Equity settled awards consist 80% of PSUs and 20% of stock options. The Company’s stock-based compensation awards outstanding as at December 31, 2020, include PSUs, deferred share units (“DSUs”), and stock options.
In accordance with the 2007 Equity Incentive Plan, as amended, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 23,306,100 shares to 39,806,100 shares.
The following table provides information about PSU, DSU and stock option activity for the year ended December 31, 2020:
PSUs DSUs Stock Options
Number of Outstanding Share Units Number of Outstanding Share Units Number of Outstanding Stock Options Weighted Average Exercise Price /Stock Option ($)
Balance, December 31, 2019
11,371,367 1,251,994 10,612,872 $ 2.78
Granted 15,897,575 2,815,903 8,893,140 0.70
Exercised (2,366,351) - - -
Forfeited (1,629,187) - (1,038,093) 2.04
Expired - - (3,022,970) 3.42
Balance, December 31, 2020
23,273,404 4,067,897 15,444,949 $ 1.50
Vested and exercisable, at December 31, 2020
5,443,796 $ 2.39
Vested, or expected to vest, at December 31, 2020 through the life of the options
14,938,829 $ 1.53
Stock-based compensation expense for the year ended December 31, 2020, was $1.2 million (2019 - $1.4 million) and was primarily recorded in G&A expenses.
At December 31, 2020, there was $5.9 million (December 31, 2019 - $6.7 million) of unrecognized compensation cost related to unvested PSUs and stock options which is expected to be recognized over a weighted average period of 1.7 years. The weighted-average remaining contractual term of options vested, or expected to vest, at December 31, 2020 was 3.2 years.
PSUs
PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company's Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest after three years, subject to the continued employment of the grantee. Upon vesting, the underlying number of Common Shares or the cash payment equivalent to their value may range from nil to 200% of the number of PSU's vested, based on the Company’s performance with respect to the applicable performance targets. As at December 31, 2020, 2.7 million (December 31, 2019 - 2.4 million) of PSU's had vested and will be settled in cash. The performance targets for the PSUs outstanding as at December 31, 2020, were as follows:
(i) 50% of the award is subject to targets relating to the total shareholder return (“TSR”) of the Company against a group of
peer companies;
(ii) 25% of the award is subject to targets relating to net asset value ("NAV") of the Company per share and NAV is based on
before tax net present value discounted at 10% of proved plus probable reserves; and
(iii) 25% of the award is subject to targets relating to the execution of corporate strategy.
The compensation cost of PSUs is subject to adjustment based upon the attainability of these performance targets. No settlement will occur with respect to the portion of the PSU award subject to each performance target for results below the applicable minimum threshold for that target. PSUs in excess of the target number granted will vest and be settled if performance exceeds the targeted performance goals. The Company currently intends to settle the PSUs in cash.
DSUs
DSUs entitle the holder to receive, either the underlying number of shares of the Company's Common Stock upon vesting of such units or, at the option of the Company, a cash payment equal to the value of the underlying shares. Once a DSU is vested, it is immediately settled. During the year ended December 31, 2020, DSUs were granted to directors and will vest 100% at such time the grantee ceases to be a member of the Board of Directors. The Company currently intends to settle the DSUs in cash.
Stock Options
Each stock option permits the holder to purchase one share of Common Stock at the stated exercise price. The exercise price equals the market price of a share of Common Stock at the time of grant. Stock options generally vest over three years. The term of stock options granted starting in May of 2013 is five years or three months after the grantee’s end of service to the Company, whichever occurs first.
For the years ended December 31, 2020 and 2019 , no stock options were exercised and no cash proceeds were received.
At December 31, 2020, the weighted average remaining contractual term of outstanding stock options was 3.2 years, (exercisable stock options - 1.9 years).
The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model based on assumptions noted in the following table:
Year Ended December 31,
2020 2019
Dividend yield (per share) Nil Nil
Volatility 50% to 69%
48% to 54%
Weighted average volatility 52 % 51 %
Risk-free interest rate 0.3% to 1.7%
1.5% to 2.5%
Expected term 5 years
4-5 years
The weighted average grant date fair value for options granted in the year ended December 31, 2020 was $0.29 (2019 - $0.89; 2018 - $1.15). The weighted average grant date fair value for options vested in the year ended December 31, 2020 was $0.79 (2019 - $1.10). The total fair value of stock options vested during year ended December 31, 2020 was $1.9 million (2019 - $1.9 million).
Weighted Average Shares Outstanding
Year Ended December 31,
2020 2019
Weighted average number of common and exchangeable shares outstanding 366,981,556 376,495,306
Shares issuable pursuant to stock options - 87,204
Shares assumed to be purchased from proceeds of stock options - (74,698)
Weighted average number of diluted common and exchange shares outstanding 366,981,556 376,507,812
For the year ended December 31, 2020, all options, on a weighted average basis, (2019 - 9,465,737 options) were excluded from the diluted (loss) earnings per share calculation as the options were anti-dilutive.
10. Asset Retirement Obligation
Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Balance, beginning of year $ 43,419 $ 43,799
Liability incurred 909 7,034
Settlements (201) (846)
Accretion 3,464 3,436
Revisions in estimated liability 623 (10,004)
Balance, end of year $ 48,214 $ 43,419
Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling asset retirement obligations. At December 31, 2020, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was $3.8 million (December 31, 2019 - $2.8 million). These assets were accounted for as restricted cash and cash equivalents on the Company's balance sheet (Note 16).
11. Revenue
Most of the Company's revenue is generated from oil sales at prices which reflect the blended prices received upon shipment by the purchaser at defined sales points or are defined by contract relative to ICE Brent and adjusted for Vasconia or Castilla crude differentials, and quality and transportation discounts each month. For the year ended December 31, 2020, 100% (2019 - 100%) of the Company's revenue resulted from oil sales and quality and transportation discounts were 25% (2019 - 16%) of the ICE Brent price. During the year ended December 31, 2020, the Company's production was sold primarily to three major customers in Colombia (2019 - three) of which equaled 41%, 31% and 25% of total sales volumes respectively.
As at December 31, 2020, accounts receivable included $0.1 million of accrued sales revenue related to December 2020 production (as at December 31, 2019, $0.1 million related to December 2019 production).
12. 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. Below is a break-down of the costs:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Operating expenses $ 2,482 $ -
Transportation costs 197 -
COVID-19 costs $ 2,679 $ -
13. Taxes
The income tax expense and recovery reported differs from the amount computed by applying the statutory rate to income (loss) before income taxes for the following reasons:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Income (loss) before income taxes
United States $ (19,065) $ (27,984)
Foreign (834,296) 123,959
(853,361) 95,975
Statutory rate (1)
32 % 33 %
Income tax (recovery) expense expected (273,076) 31,672
Impact of foreign taxes 26,668 9,387
Foreign currency translation 48,734 11,527
Goodwill Impairment 32,826 -
Stock-based compensation 666 430
Change in valuation allowance 75,241 3,429
Non-deductible third party royalty in Colombia 697 2,240
Other permanent differences 5,349 6,082
Non-deductible investment loss (gain) (PetroTal) 7,501 (7,482)
Total income tax (recovery) expense $ (75,394) $ 57,285
Effective tax rate 9 % 60 %
Current income tax expense
Foreign 754 17,058
754 17,058
Deferred income tax expense (recovery)
Foreign (76,148) 40,227
Total income tax (recovery) expense $ (75,394) $ 57,285
(1) The tax rate is the statutory rate in Colombia.
In general, it is the Company's practice and intention to reinvest the earnings of our non-U.S. subsidiaries in such subsidiaries' operations. As of December 31, 2020, the Company has not made a provision for U.S. or additional foreign withholding taxes on the investments in foreign subsidiaries that are indefinitely reinvested. Generally, such amounts become subject to taxation upon the remittance of dividends and under certain other circumstances.
In the fourth quarter of 2019, the Colombia government enacted a new tax reform to replace the 2018 tax reform, which was overturned by the Colombian Constitutional Court. This new tax reform maintains the same corporate tax rates that were approved by Congress in 2018. The enacted corporate tax rates are 32% for 2020, 31% for 2021 and 30% for 2022 and onwards. The tax rates applied to the calculation of deferred income taxes, before valuation allowances, have been adjusted to reflect these changes.
As at December 31,
(Thousands of U.S. Dollars) 2020 2019
Deferred tax assets
Tax benefit of operating loss carryforwards $ 100,616 $ 73,096
Tax basis in excess of book basis 37,698 544
Foreign tax credits and other accruals 86,664 76,720
Tax benefit of capital loss carryforwards 27,661 22,710
Deferred tax assets before valuation allowance 252,639 173,070
Valuation allowance (195,321) (129,067)
Deferred tax assets - long-term 57,318 44,003
Deferred tax liabilities - 59,762
Net deferred tax assets (liabilities) $ 57,318 $ (15,759)
At December 31, 2020, the Company has not recognized the benefit of unused non-capital loss carryforwards of $46.0 million (2019 - $50.5 million) for federal purposes in the United States, which expire from 2029 to 2040.
At December 31, 2020, the Company has not recognized the benefit of unused non-capital loss carryforwards of $33.1 million (2019 - $31.5 million) for federal and provincial purposes in Canada, which expire from 2029 to 2039. The Company has not recognized the benefit of capital loss carry forwards of $240.5 million (2019 - $197.5 million) for federal and provincial purposes in Canada which can be carried forward indefinitely.
At December 31, 2020, the Company has recognized the benefit of unused non-capital loss carryforwards of $115.6 million (2019 - $140.5 million), out of a total of $252.0 million and tax credits of $1.0 million (2019 - $1.5 million), out of a total of $3.9 million, for federal purposes in Colombia. As a result of the 2016 Colombian Tax Reform, Colombian losses can be carryforward for a period of 12 years, and not indefinitely as under the previous tax regime. There is a grandfathering rule for losses incurred prior to 2017, which may continue to be carried forward indefinitely. Colombian losses of $33.7 million can be carried forward indefinitely and $218.3 million are entitled to a carryforward period of 12 years.
As at December 31, 2020 and 2019, Gran Tierra had no unrecognized tax benefits and related interest and penalties included in its deferred and current tax liabilities in the consolidated balance sheet. The Company does not anticipate any material changes with respect to unrecognized tax benefit within the next twelve months. The Company had no other significant interest or penalties related to taxes included in the consolidated statement of operations for the quarter ended December 31, 2020. The Company and its subsidiaries file income tax returns in the U.S. and certain other foreign jurisdictions. The Company is subject to income tax examinations for the tax years ended 2012 through 2020 in certain jurisdictions.
In the fourth quarter of 2019, $1.4 million of value added tax receivable was written-off mainly as a result of internal restructuring of our Colombian entities.
14. Commitments and Contingencies
Purchase Obligations, Firm Agreements and Leases
As at December 31, 2020, future minimum payments under non-cancelable agreements with remaining terms in excess of one year were as follows:
Year ending December 31
(Thousands of U.S. Dollars) Total 2021 2022 2023 2024 2025 Thereafter
Operating leases (1)
4,910 2,330 2,077 503 - - -
Finance leases (1)
4,725 3,197 1,444 57 27 - -
Software and Telecommunication 900 300 300 300 - - -
$ 10,535 $ 5,827 $ 3,821 $ 860 $ 27 $ - $ -
(1) Including maintenance and operating costs.
Gran Tierra has operating leases for office spaces and finance leases for water flood facilities and storage tanks and commitments relating to compressors, vehicles, equipment and housing.
Indemnities
Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated. The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.
Letters of Credit
At December 31, 2020, the Company had provided letters of credit and other credit support totaling $100.6 million (December 31, 2019 - $120.6 million) as security relating to work commitment guarantees contained in exploration contracts in Colombia and Ecuador and other capital or operating requirements.
Contingencies
Gran Tierra has a number of lawsuits and claims pending including a dispute with the ANH relating to the calculation of HPR royalties. Although the outcome of these other lawsuits and disputes cannot be predicted with certainty, Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. Gran Tierra records costs as they are incurred or become probable and determinable.
15. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk
Financial Instruments
At December 31, 2020, the Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, investment, derivatives, accounts payable and accrued liabilities, long-term debt, current and long-term equity compensation reward liability and other long-term liabilities.
Fair Value Measurement
The fair value of investment, derivatives and PSU liabilities is being remeasured at the estimated fair value at the end of each reporting period.
The fair value of the Company's investment in PetroTal was estimated to be $48.3 million and $94.7 million as at December 31, 2020 and 2019, respectively, based on the closing stock price of PetroTal of $0.20 ($0.25 CAD) and $0.38 ($0.50 CAD) per share as at December 31, 2020 and 2019, respectively.
The fair value of commodity price and foreign currency derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
The fair value of the PSU liability was estimated based on option pricing model using the inputs, such as quoted market prices in an active market, and PSU performance factor.
The fair value of investment, derivatives, PSU and DSU liabilities at December 31, 2020 and December 31, 2019 were as follows:
As at December 31,
(Thousands of U.S. Dollars) 2020 2019
Investment $ 48,323 $ 94,741
Derivative liability $ 12,050 $ 775
PSU and DSU liability 4,760 7,859
$ 16,810 $ 8,634
The following table presents gains or losses on financial instruments recognized in the accompanying consolidated statements of operations:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Commodity price derivative (gain) loss $ (220) $ 3,642
Foreign currency derivative loss 3,155 27
Investment loss (gain) 46,883 (49,884)
Financial instruments loss 1,164 -
$ 50,982 $ (46,215)
These gains or losses are presented as financial instruments gains or losses in the consolidated statements of operations and cash flows.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs consist of quoted prices (unadjusted) in active markets for identical assets and liabilities and have the highest priority. Level 2 and 3 inputs are based on significant other observable inputs and significant unobservable inputs, respectively, and have lower priorities. The Company uses appropriate valuation techniques based on the available inputs to measure the fair values of assets and liabilities.
Financial instruments not recorded at fair value at December 31, 2020 include the Senior Notes and the Revolving Credit Facility (Note 8). At December 31, 2020, the carrying amounts of the 6.25% Senior Notes and 7.75% Senior Notes were $292.3 million and $290.9 million, respectively, which represents the aggregate principal amount less unamortized debt issuance costs, and the fair values were $205.5 million and $206.9 million. The fair value of the Revolving Credit Facility approximates its carrying value. The fair value of the Senior Notes is determined based on quoted market prices considered Level 1 inputs. The fair value of the Revolving Credit Facility is estimated based on the amount the Company would have to pay a third party to assume the debt, including the credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company's default or repayment risk. The credit spread (premium or discount) is determined by comparing the debt to new issuances (secured or unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of the Revolving Credit Facility was estimated using level 2 inputs.
The fair value of long-term restricted cash and cash equivalents and the revolving credit facility approximated their carrying value because interest rates are variable and reflective of market rates. The fair values of other financial instruments approximate their carrying amounts due to the short-term maturity of these instruments.
At December 31, 2020, the fair value of the investment and DSU liability was determined using Level 1 inputs and the fair value of derivatives and PSUs was determined using Level 2 inputs.
The Company’s non-recurring fair value measurements include asset retirement obligations. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. The significant level 3 inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free interest rate, inflation rates and estimated dates of abandonment. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets.
Commodity Price Risk
The Company may at time utilize commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. As at December 31, 2020, the Company had outstanding commodity price derivative positions as follows:
Period and Type of Instrument Volume,
bopd Reference Sold Put ($/bbl, Weighted Average) Purchased Put ($/bbl, Weighted Average) Sold Call
($/bbl, Weighted Average) Premium
($/bbl, Weighted Average)
Three-way Collars: January 1, to June 30, 2021 14,000 ICE Brent 36.43 45.14 51.45 0.21
Collars: January 1, to June 30, 2021 1,000 ICE Brent n/a 45.00 50.40 n/a
Swaptions: July 1, to December 31, 2021 3,000 ICE Brent n/a n/a 56.75 n/a
Subsequent to year end, the Company entered into the following commodity price derivative positions:
Period and Type of Instrument Volume,
bopd Reference Sold Put ($/bbl, Weighted Average) Purchased Put ($/bbl, Weighted Average) Sold Call
($/bbl, Weighted Average) Premium
($/bbl, Weighted Average)
Three-way Collars: July 1, to December 31, 2021 4,000 ICE Brent 45.00 55.00 68.00 n/a
Foreign Exchange Risk
The Company is exposed to foreign exchange risk in relation to its Colombian operations predominantly in operating costs, general and administrative costs and transportation costs. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign exchange derivatives. As at December 31, 2020 the Company had no outstanding foreign currency derivative positions. Subsequent to year end, the Company entered into the following foreign currency derivative positions:
Period and Type of Instrument Amount Hedged
(Millions of COP) U.S. Dollar Equivalent of Amount Hedged (Thousands of U.S. Dollars)(1)
Reference Floor Price
(COP, Weighted Average) Cap Price (COP, Weighted Average)
Collars: March 1, to December 31, 2021 10,000 3,051 COP 3,500 3,630
(1) At December 31, 2020 foreign exchange rate.
Unrealized foreign exchange gains and losses primarily result from fluctuation of the U.S. dollar to the Colombian peso and Canadian dollar due to Gran Tierra’s current and deferred tax assets, taxes receivable and investment, which are monetary assets and liabilities mainly denominated in the local currencies. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A strengthening in one Colombian peso against the U.S. dollar results in foreign exchange gain of approximately $12,000 on deferred tax asset balance and a foreign exchange gain of approximately $26,000 on taxes receivable. The strengthening of one Canadian cent against the U.S. dollar results in foreign exchange gain of $0.4 million on investment balance. This effect was calculated based on the Company's December 31, 2020, deferred tax asset and investment balances.
For the years ended December 31, 2020 and 2019, respectively, 100% of the Company's oil sales were generated in Colombia. In Colombia, the Company receives 100% of its revenues in U.S. dollars and the majority of its capital expenditures are in U.S. dollars or are based on U.S. dollar prices.
Credit Risk
Credit risk arises from the potential that the Company may incur a loss if counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents, restricted cash and accounts receivable. The carrying value of cash and cash equivalents, restricted cash and accounts receivable reflects management’s assessment of credit risk.
At December 31, 2020, cash and cash equivalents and restricted cash included balances in bank accounts, term deposits and certificates of deposit, placed with financial institutions with investment grade credit ratings.
Most of the Company’s accounts receivable relate to sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis and obtaining letters of credits from customers which amounted to $8.9 million as of December 31, 2020. For the years ended December 31, 2020 and 2019, respectively, the Company had three customers which were over 10% of sales.
To reduce the concentration of exposure to any individual counterparty, the Company utilizes a group of investment-grade rated financial institutions for its derivative transactions. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments.
16. Supplemental Cash Flow Information
The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company's consolidated balance sheet that sum to the total of the same such amounts shown in the consolidated statements of cash flows:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Cash and cash equivalents $ 13,687 $ 8,301
Restricted cash and cash equivalents - current 427 516
Restricted cash and cash equivalents - long-term (1)
3,409 2,258
$ 17,523 $ 11,075
(1) The long-term portion of restricted cash is included in other long-term assets on the Company's balance sheet.
Net changes in assets and liabilities from operating activities were as follows:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Accounts receivable and other long-term assets $ 27,607 $ (5,680)
Derivatives 2,302 (638)
Inventory (2,628) (3,179)
Other prepaids (279) 583
Accounts payable and accrued and other long-term liabilities (47,194) (1,367)
Prepaid tax and taxes receivable and payable 56,254 (83,593)
Net changes in assets and liabilities from operating activities $ 36,062 $ (93,874)
The following table provides additional supplemental cash flow disclosures:
Year Ended December 31,
(Thousands of U.S. Dollars) 2020 2019
Cash paid for income taxes $ 15,476 $ 49,196
Cash paid for interest $ 50,209 $ 37,767
Non-cash investing activities
Net liabilities related to property, plant and equipment, end of year $ 28,711 $ 77,353
17. Subsequent Events
Subsequent to December 31, 2020, the Company sold 44% percent (109,006,250 common shares) of its interest in PetroTal for cash proceeds of $14.9 million resulting in a loss on sale of $5.1 million.
Supplementary Data (Unaudited)
1) Oil and Gas Producing Activities
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities-Oil and Gas”, and regulations of the U.S. Securities and Exchange Commission (SEC), the Company is making certain supplemental disclosures about its oil and gas exploration and production operations.
A. Estimated Proved NAR Reserves
The following table sets forth Gran Tierra's estimated proved NAR reserves and total net proved developed and undeveloped reserves as of December 31, 2018, 2019 and 2020, and the changes in total net proved reserves during the two-year period ended December 31, 2020.
The net proved reserves represent management’s best estimate of proved oil and natural gas reserves after royalties. Reserve estimates for each property are prepared internally each year and 100% of the reserves at December 31, 2020, have been evaluated by independent qualified reserves consultants, McDaniel & Associates Consultants Ltd.
The reserve estimation process requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property, and demonstrate reasonable certainty that they are recoverable from known reservoirs under economic and operating conditions that existed at year end. The determination of oil and natural gas reserves is complex and requires significant judgment. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. The process of estimating oil and gas reserves is complex and requires significant judgment, as discussed in Item 1A “Risk Factors”. See “Critical Accounting Policies and Estimates” in Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” for a description of Gran Tierra’s reserves estimation process.
Colombia
Liquids (1)
Gas
(Mbbl) (MMcf)
Proved NAR Reserves, December 31, 2018
53,922 2,182
Purchases of reserves in place 4,495 -
Extensions 6,106 -
Technical revisions 13,336 73
Production (10,530) (361)
Proved NAR Reserves, December 31, 2019
67,329 1,894
Improved Recoveries 961 -
Extensions 879 -
Technical revisions 2,477 (40)
Production (6,954) (199)
Proved NAR Reserves, December 31, 2020
64,692 1,655
Proved Developed Reserves NAR, December 31, 2018
36,805 1,253
Proved Developed Reserves NAR, December 31, 2019
36,465 1,008
Proved Developed Reserves NAR, December 31, 2020
38,660 633
Proved Undeveloped Reserves NAR, December 31, 2018
17,117 929
Proved Undeveloped Reserves NAR, December 31, 2019
30,864 886
Proved Undeveloped Reserves NAR, December 31, 2020
26,032 1,022
(1) At December 31, 2020, 2019, and 2018, liquids reserves are 100% oil.
Changes in proved reserves during the year ended December 31, 2020 shown in the table above primarily resulted from the following significant factors:
Improved Recoveries. Added 1.0 MMBOE of proved reserves, during the year ended December 31, 2020, which were attributed to improved recoveries of heavy oil in the Acordionero field.
Extensions. Added 0.9 MMBOE of proved 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.
Technical and Economic Revisions. Added 2.5 MMBOE of proved reserves, during the year ended December 31, 2020, primarily related to positive technical revisions, based on performance and waterflood response, in the Acordionero, Costayaco, Moqueta and Cohembi fields.
B. Capitalized Costs
Capitalized costs for Gran Tierra's oil and gas producing activities consisted of the following at the end of each of the years in the two-year period ended December 31, 2020:
(Thousands of U.S. Dollars) Proved Properties Unproved Properties Accumulated
Depletion,
Depreciation
and
Impairment Net Capitalized Costs
Balance, December 31, 2020
$ 4,106,768 $ 161,763 $ (3,309,413) $ 959,118
Balance, December 31, 2019
$ 3,850,565 $ 310,809 $ (2,591,631) $ 1,569,743
C. Costs Incurred
The following table presents costs incurred for Gran Tierra's oil and gas property acquisitions and exploration and development for the respective years:
(Thousands of U.S. Dollars) Total
Year Ended December 31, 2020
Property acquisition costs
Proved $ -
Unproved $ -
Exploration costs $ 12,852
Development costs $ 92,773
Year Ended December 31, 2019
Property acquisition costs
Proved $ 53,650
Unproved $ 48,648
Exploration costs $ 97,648
Development costs $ 281,151
D. Results of Operations for Oil and Gas Producing Activities
(Thousands of U.S. Dollars) Colombia
December 31, 2020
Oil sales $ 237,838
Production costs (122,431)
Exploration expenses -
DD&A expenses (164,013)
Asset impairment (564,495)
Income tax expense 75,394
Results of Operations $ (537,707)
December 31, 2019
Oil sales $ 570,983
Production costs (203,604)
Exploration expenses -
DD&A expenses (224,045)
Asset impairment -
Income tax expense (53,989)
Results of Operations $ 89,345
E. Standardized Measure of Discounted Future Net Cash Flows and Changes
The following disclosure is based on estimates of net proved reserves and the period during which they are expected to be produced. Future cash inflows are computed by applying the twelve month period unweighted arithmetic average of the price as of the first day of each month within that twelve month period, unless prices are defined by contractual arrangements, excluding
escalations based on future conditions to Gran Tierra’s after royalty share of estimated annual future production from proved oil and gas reserves.
Colombia
Twelve month period unweighted arithmetic average of the wellhead price as of the first day of each month within the twelve month period
2020 $ 35.33
2019 $ 54.05
Weighted average production costs
2020 $ 12.90
2019 $ 18.67
Future development and production costs to be incurred in producing and further developing the proved reserves are based on year end cost indicators. Future income taxes are computed by applying year end statutory tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows. Discounted future net cash flows are calculated using 10% mid-year discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results.
The Company believes this information does not in any way reflect the current economic value of its oil and gas producing properties or the present value of their estimated future cash flows as:
•no economic value is attributed to probable and possible reserves;
•use of a 10% discount rate is arbitrary; and
•prices change constantly from the twelve-month period unweighted arithmetic average of the price as of the first day of each month within that twelve-month period.
The standardized measure of discounted future net cash flows from Gran Tierra's estimated proved oil and gas reserves is as follows:
(Thousands of U.S. Dollars) Colombia
December 31, 2020
Future cash inflows $ 2,329,016
Future production costs (929,591)
Future development costs (252,347)
Future asset retirement obligations (43,455)
Future income tax expense (104,311)
Future net cash flows 999,312
10% discount (271,825)
Standardized Measure of Discounted Future Net Cash Flows $ 727,487
December 31, 2019
Future cash inflows $ 3,711,517
Future production costs (1,429,689)
Future development costs (351,750)
Future asset retirement obligations (46,922)
Future income tax expense (288,088)
Future net cash flows 1,595,068
10% discount (406,872)
Standardized Measure of Discounted Future Net Cash Flows $ 1,188,196
Changes in the Standardized Measure of Discounted Future Net Cash Flows
The following table summarizes changes in the standardized measure of discounted future net cash flows for Gran Tierra's proved oil and gas reserves during two years ended December 31, 2020:
(Thousands of U.S. Dollars) 2020 2019
Balance, beginning of year $ 1,188,196 $ 1,194,460
Sales and transfers of oil and gas produced, net of production costs (442,826) (595,872)
Net changes in prices and production costs related to future production (813,627) (387,603)
Extensions, discoveries and improved recovery, less related costs 47,271 200,486
Previously estimated development costs incurred during the year (150,644) 155,287
Revisions of previous quantity estimates 700,106 731,352
Accretion of discount 118,820 119,446
Purchases of reserves in place - 98,244
Net change in income taxes 128,265 (92,527)
Changes in future development costs (48,074) (235,077)
Net decrease (460,709) (6,264)
Balance, end of year $ 727,487 $ 1,188,196

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule 13a-15(b) of the Exchange Act. Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra's disclosure controls and procedures were effective as of December 31, 2020, to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Gran Tierra, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2020. The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by KPMG LLP, an independent registered public accounting firm, which audited our financial statements included in this Annual Report on Form 10-K as stated in their report which appears herein.
Changes in Internal Controls over Financial Reporting
There were no changes in our internal controls over financial reporting during the three months ended December 31, 2020, that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors of Gran Tierra Energy Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Gran Tierra Energy Inc.’s (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements), and our report dated February 24, 2021 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Chartered Professional Accountants
Calgary, Canada
February 24, 2021

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
The Board of Directors of Gran Tierra Energy Inc. has established May 5, 2021 as the date of the Company’s 2021 Annual Meeting of Stockholders (the “2021 Annual Meeting”) and March 9, 2021 as the record date for determining stockholders entitled to notice of, and to vote at, the 2021 Annual Meeting. The time and location of the 2021 Annual Meeting will be as set forth in the Company’s proxy materials for the 2021 Annual Meeting.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required regarding our directors is incorporated herein by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our definitive Proxy Statement for the 2021 Annual Meeting of Stockholders (our “Proxy Statement”), a copy of which will be filed with the SEC within 120 days after December 31, 2020. For information with respect to our executive officers, see “Information About Our Executive Officers” at the end of Part I of this report, following Item 4 “Mine Safety Disclosures”.
The information required regarding Section 16(a) beneficial ownership reporting compliance, if applicable, is incorporated by reference from the information contained in the section entitled “Delinquent Section 16(a) Reports” in our Proxy Statement.
The information required with respect to procedures by which security holders may recommend nominees to our Board of Directors, the composition of our Audit Committee, and whether we have an “audit committee financial expert”, is incorporated by reference from the information contained in the section entitled “Proposal 1 - Election of Directors” in our Proxy Statement.
Adoption of Code of Ethics
Gran Tierra has adopted a Code of Business Conduct and Ethics (the “Code”) applicable to all of its Board members, employees and executive officers, including its President and Chief Executive Officer, Director (Principal Executive Officer), and Chief Financial Officer and Executive Vice President, Finance (Principal Financial and Accounting Officer). Gran Tierra has made the Code available on its website at www.grantierra.com.
Gran Tierra intends to satisfy the public disclosure requirements regarding (1) any amendments to the Code, or (2) any waivers under the Code given to Gran Tierra’s (Principal Executive Officer) and (Principal Financial and Accounting Officer) by posting such information on its website at http://www.grantierra.com/governance.html within four business days of such amendment or waiver. Information on our website is not incorporated into this Annual Report or otherwise made part of this Annual Report.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required regarding the compensation of our directors and executive officers is incorporated herein by reference from the information contained in the section entitled “Executive Compensation and Related Information” in our Proxy Statement, including under the subheadings “Director Compensation,” “Compensation Committee Report” and “Compensation Committee Interlocks and Insider Participation”.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Certain Beneficial Owners and Management
The information required regarding security ownership of our 10% or greater stockholders and of our directors and management is incorporated herein by reference from the information contained in the section entitled “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement.
The following table provides certain information with respect to securities authorized for issuance under Gran Tierra’s equity compensation plans in effect as of the end of December 31, 2020:
Plan category (a)
Number of securities to be issued upon exercise of outstanding options (1)
(b)
Weighted average exercise price of outstanding options
(c)
Number of securities remaining available for future issuance under equity compensation plans, excluding securities reflected in column (a) (2)
Equity compensation plans approved by security holders 15,444,949 1.50 7,223,817
Equity compensation plans not approved by security holders - - -
15,444,949 1.50 7,223.817
(1) Includes shares reserved to be issued pursuant to stock options granted pursuant to the 2007 Equity Incentive Plan ("the Plan"), which is an amendment and restatement of our 2005 Equity Incentive Plan. This does not include any shares reserved to be issued relating to performance stock units ("PSU's"), and deferred share units (DSU's"), which may be settled in cash or in shares of our common stock at our election, and for which management's intent to cash settle is reflected in the financial statement classification of these awards as financial liabilities.
(2) In accordance with Item 201(d) of Regulation S-K, the figure in this column represents the total number of shares of our common stock remaining available for issuance under the Plan as of December 31, 2020, minus the awards reported in column (a), above. Note, pursuant to the terms of the Plan, the pool of shares available for grant thereunder is not actually reduced until an award is settled in shares of our common stock (as opposed to reducing the pool at the time of grant). At December 31, 2020, 27,341,301 shares were issued and outstanding relating to PSUs and DSUs and, after application of the fungible factor of 1.55, these outstanding awards would represent a 42,379,017 reduction to the securities remaining available for future issuance under the Plan if such awards were to be equity settled. Consistent with accounting treatment that reflects management's intent to cash settle, these amounts are not included in the above table as a reduction in the securities remaining available for future issuance. Pursuant to the provisions of the Plan, the number of securities remaining available for issuance is reduced by the aggregate balance of (i) stock options exercised and outstanding at a fungible factor of 1.0 shares and (ii) unit based awards at a fungible factor of 1.55 shares for each share of our common stock issued pursuant to any equity settled awards granted under the Plan. Accordingly, the number of shares available for future awards under the Plan may be different than the amount shown in this column.
The only equity compensation plan approved by our stockholders is our 2007 Equity Incentive Plan, which is an amendment and restatement of our 2005 Equity Plan.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required regarding related transactions is incorporated herein by reference from the information contained in the section entitled “Certain Relationships and Related Transactions” and, with respect to director independence, the section entitled “Proposal 1 - Election of Directors”, in our Proxy Statement.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required is incorporated herein by reference from the information contained in the sections entitled “Principal Accountant Fees and Services” and “Pre-Approval Policies and Procedures” in the proposal entitled “Ratification of Selection of Independent Auditors” in our Proxy Statement.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this Annual Report on Form 10-K:
(1) Financial Statements
Page
Report of Independent Registered Public Accounting Firm 55
Consolidated Statements of Operations 58
Consolidated Balance Sheets 59
Consolidated Statements of Cash Flow 60
Consolidated Statements of Shareholders’ Equity 61
Notes to the Consolidated Financial Statements 62
Supplementary Data (Unaudited) 82
(2) Financial Statement Schedules
None.
(3) Exhibits
Exhibit No. Description Reference
2.2 Plan of Conversion, dated October 31, 2016.
Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
3.1 Certificate of Incorporation.
Incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
3.2 Bylaws of Gran Tierra Energy Inc.
Incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K, filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
3.3 Certificate of Retirement of Special A Voting Stock and Special B Voting Stock of Gran Tierra Energy Inc.
Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K, filed with the SEC on July 9, 2018 (SEC File No. 001-34018).
4.1 Indenture related to the 5.00% Convertible Senior Notes due 2021, dated as of April 6, 2016, between Gran Tierra Energy Inc. and U.S. Bank National Association.
Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).
4.2 Form of 5.00% Convertible Senior Notes due 2021.
Incorporated by reference in Exhibit A to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).
4.3 Subscription Receipt Agreement, dated July 8, 2016, by and between Gran Tierra Energy Inc. and Computershare Trust Company of Canada.
Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).
4.4 Form of Registration Rights Agreement.
Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K, filed with the SEC on July 14, 2016 (SEC File No. 001-34018).
4.5 Indenture related to the 6.25% Senior Notes due 2025, dated as of February 15, 2018, between Gran Tierra Energy International Holdings Ltd., the Guarantors named therein and U.S. Bank National Association.
Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).
4.6 First Supplemental Indenture related to 6.25% Senior Notes due 2025, dated as of July 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank National Association.
Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, filed with the SEC on August 8, 2019 (SEC File No. 001-34018).
4.7 Form of 6.25% Senior Notes due 2025.
Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on February 16, 2018 (SEC File No. 001-34018).
4.8 Indenture related to the 7.750% Senior Notes due 2027, dated as of May 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank National Association.
Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).
4.9 First Supplemental Indenture related to 7.750% Senior Notes due 2027, dated as of July 23, 2019, among Gran Tierra Energy Inc., the guarantors named therein, and U.S. Bank.
Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, filed with the SEC on August 8, 2019 (SEC File No. 001-34018).
4.10 Form of 7.750% Senior Notes due 2027 (included as Exhibit A to Exhibit 4.1).
Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed with the SEC on May 23, 2019 (SEC File No. 001-34018).
4.11 Description of securities.
Incorporated by reference to Exhibit 4.11 to the Annual Report on Form 10-K, filed with the SEC on February 27, 2020 (SEC File No. 001-34018).
10.1 Share Purchase Agreement dated as of June 30, 2016, among Gran Tierra Energy International Holdings Ltd., Tribeca Oil & Gas Inc., Macquarie Bank Limited, Rorick Ventures Group Inc., as vendors, and PetroLatina Energy Limited.
Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed with the SEC on July 7, 2016 (SEC File No. 001-34018).
10.2 Share and Loan Purchase Agreement, dated February 5, 2017, by Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S. Á. R.L. and Maha Energy AB
Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed with the SEC on July 6, 2017
(SEC File No. 001-34018).
10.3 Amendment #1, dated May 30, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha
Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K filed with the SEC on July 6, 2017
(SEC File No. 001-34018).
10.4 Amendment #2, dated June 22, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha
Incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K filed with the SEC on July 6, 2017
(SEC File No. 001-34018)
10.5 Amendment #3, dated June 26, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha
Incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K filed with the SEC on July 6, 2017 (SEC File No. 001-34018).
10.6 Amendment #4, dated August 31, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.
Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the SEC on November 2, 2017 (SEC File No. 001-34018).
10.7 Amendment #5, dated October 26, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.
Incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K filed with the SEC on February 27, 2018 (SEC File No. 001-34018).
10.8 Amendment #6, dated November 8, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.
Incorporated by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed with the SEC on February 27, 2018 (SEC File No. 001-34018).
10.9 Amendment #7, dated November 17, 2017, to the Share and Loan Purchase Agreement dated February 5, 2017 between Gran Tierra Energy International Holdings Ltd., Gran Tierra Luxembourg Holdings S.Á.R.L. and Maha Energy AB.
Incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K filed with the SEC on February 27, 2018 (SEC File No. 001-34018).
10.10 Amended and Restated 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed with the SEC on August 7, 2012 (SEC File No. 001-34018).
10.11 Form of Restricted Stock Unit Award Agreement Under the 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on August 7, 2013 (SEC File No. 001-34018).
10.12 Form of Option Agreement Under the 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the SEC on August 7, 2013 (SEC File No. 001-34018).
10.13 Form of Indemnity Agreement.*
Incorporated by reference to Exhibit 3.5 to the Current Report on Form 8-K filed with the SEC on November 4, 2016 (SEC File No. 001-34018).
10.14 Form of Deferred Stock Unit Award Agreement Under the 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 10.29 to the Annual Report on Form 10-K, filed with the SEC on February 29, 2016 (SEC File No. 001-34018).
10.15 Form of Deferred Stock Unit Grant Notice.*
Incorporated by reference to Exhibit 10.30 to the Annual Report on Form 10-K, filed with the SEC on February 29, 2016 (SEC File No. 001-34018).
10.16 Executive Employment Agreement effective May 7, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Gary Guidry.*
Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2015 (SEC File No. 001-34018).
10.17 Executive Employment Agreement effective May 11 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Lawrence West.*
Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2015 (SEC File No. 001-34018).
10.18 Executive Employment Agreement effective May 11, 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and James Evans.*
Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q, filed with the SEC on November 4, 2015 (SEC File No. 001-34018).
10.19 Form of Performance Stock Unit Award Agreement Under the 2007 Equity Incentive Plan.*
Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2016 (SEC File No. 001-34018).
10.20 Form of Performance Stock Unit Grant Notice.*
Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2016 (SEC File No. 001-34018).
10.21 Executive Employment Agreement effective May 11 2015, between Gran Tierra Energy Canada ULC, Gran Tierra Energy Inc. and Ryan Ellson.*
Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2016 (SEC File No. 001-34018).
10.22 Credit Agreement, dated as of September 18, 2015, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2015 (SEC File No. 001-34018).
10.23 First Amendment to Credit Agreement, dated as of March 31, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K, filed with the SEC on April 6, 2016 (SEC File No. 001-34018).
10.24 Second Amendment to Credit Agreement, dated as of June 2, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on June 3, 2016 (SEC File No. 001-34018).
10.25 Third Amendment to Credit Agreement, dated as of August 23, 2016, by and among Gran Tierra Energy International Holdings Ltd., Gran Tierra Energy Inc., The Bank of Nova Scotia, and the lenders party thereto.
Incorporated by reference to Exhibit 10.42 to the Annual Report on Form 10-K, filed with the SEC on March 1, 2017 (SEC File No. 001-34018).
10.26 Fourth Amendment to Credit Agreement, dated as of November 16, 2016, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.43 to the Annual Report on Form 10-K, filed with the SEC on March 1, 2017 (SEC File No. 001-34018).
10.27 Fifth Amendment to Credit Agreement, dated as of February 13, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on February 15, 2017 (SEC File No. 001-34018).
10.28 Sixth Amendment to Credit Agreement, dated May 17, 2017 and effective as of June 1, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on May 19, 2017 (SEC File No. 001-34018).
10.29 Seventh Amendment to Credit Agreement, dated as of June 15, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q, filed with the SEC on August 4, 2017 (SEC File No. 001-34018).
10.30 Eighth Amendment to Credit Agreement, dated as of September 18, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on September 21, 2017 (SEC File No. 001-34018).
10.31 Ninth Amendment to Credit Agreement, dated as of November 10, 2017, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia, Societe Generale and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on November 14, 2017 (SEC File No. 001-34018).
10.32 Tenth Amendment to Credit Agreement, dated as of May 25, 2018, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q, filed with the SEC on August 2, 2018 (SEC File No. 001-34018)
10.33 Eleventh Amendment to Credit Agreement, dated as of December 20, 2018, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on December 21, 2018 (SEC File No. 001-34018)
10.34 Twelfth Amendment to Credit Agreement, dated as of May 14, 2019, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on May 15, 2019 (SEC File No. 001-34018)
10.35 Thirteenth Amendment to Credit Agreement, dated as of December 10, 2019, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on December 11, 2019 (SEC File No. 001-34018)
10.36 Fourteenth Amendment to Credit Agreement, dated as of June 1, 2020, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2020 (SEC File No. 001-34018) (Certain schedules and exhibits to this agreement have been omitted pursuant to Item 601(a)(5) of Registration S-K. A copy of any omitted schedule and/or exhibit will be furnished supplementally to the SEC upon request).
10.37 Fifteenth Amendment to Credit Agreement, dated as of December 7, 2020, by and among Gran Tierra Energy Inc., Gran Tierra Energy International Holdings Ltd., the Bank of Nova Scotia and the lenders party thereto.
Filed herewith (Certain portions of this exhibit have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K and certain schedules and exhibits to this agreement have been omitted pursuant to Item 601(a)(5) of Registration S-K. An unredacted copy of this exhibit and a copy of any omitted schedule and/or exhibit will be furnished supplementally to the SEC upon request).
10.38 Colombian Participation Agreement, dated as of June 22, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.55 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008 (SEC File No. 001-34018).
10.39 Amendment No. 1 to Colombian Participation Agreement, dated as of November 1, 2006, by and among Argosy Energy International, Gran Tierra Energy Inc., and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.56 to the Quarterly Report on Form 10-Q, filed with the SEC on August 11, 2008 (SEC File No. 001-34018).
10.40 Amendment No. 2 to Colombian Participation Agreement, dated as of July 3, 2008, between Gran Tierra Energy Inc. and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q/A, filed with the SEC on November 19, 2008 (SEC File No. 001-34018).
10.41 Amendment No. 3 to Participation Agreement, dated as of December 31, 2008, by and among Gran Tierra Energy Colombia, Ltd., Gran Tierra Energy Inc. and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K, filed with the SEC on January 7, 2009 (SEC File No. 001-34018).
10.42 Amendment No. 4 dated June 13, 2011, to the Colombian Participation Agreement dated June 22, 2006, between Gran Tierra Colombia Ltd and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).
10.43 Amendment No. 5 dated February 10, 2011, to the Colombian Participation Agreement dated June 22, 2006, between Gran Tierra Colombia Ltd and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).
10.44 Amendment No. 6 dated March 1, 2012, to the Colombian Participation Agreement dated June 22, 2006, between Gran Tierra Colombia Ltd and Crosby Capital, LLC.
Incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q filed with the SEC on May 7, 2012 (SEC File No. 001-34018).
10.45 Sale and Purchase Agreement for all of the issued share capital of Vetra Southeast S.L.U., dated February 20, 2019.
Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).
10.46 Sale and Purchase Agreement for PUT-8, dated February 20, 2019.
Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).
10.47 Sale and Purchase Agreement for LLA-5, dated February 20, 2019.
Incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).
10.48 Sale and Purchase Agreement for Suroriente, dated February 20, 2019.
Incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the SEC on February 25, 2019 (SEC File No. 001-34018).
10.49 Executive Employment Agreement, dated October 18, 2019, between Gran Tierra Energy Canada ULC and Gran Tierra Energy Inc. and Remi Anthony Berthelet.
Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the SEC on November 6, 2019 (SEC File No. 001-34018).
21.1 List of subsidiaries.
Filed herewith.
23.1 Consent of KPMG LLP.
Filed herewith.
23.2 Consent of McDaniel & Associates Consultants Ltd.
Filed herewith.
24.1 Power of Attorney. See signature page.
31.1 Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Filed herewith.
31.2 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Filed herewith.
32.1 Certification of Principal Executive Officer and Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Furnished herewith.
99.1 Gran Tierra Energy Inc. Reserves Assessment and Evaluation of Oil and Gas Properties Corporate Summary, effective December 31, 2019.
Filed herewith.
101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH Inline XBRL Taxonomy Extension Schema Document
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document
104. Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document
* Management contract or compensatory plan or arrangement.